The Future of Nuclear Energy
in a Carbon-Constrained WorldAN INTERDISCIPLINARY MIT STUDYThe Future of Nuclear Energy
in a Carbon-Constrained WorldAN INTERDISCIPLINARY MIT STUDY

Other Reports in the MIT Future of Series:
The Future of Nuclear Power (2003)
The Future of Geothermal Energy (2006)
The Future of Coal (2007)
Update of the Future of Nuclear Power (2009)
The Future of Natural Gas (2011)
The Future of the Nuclear Fuel Cycle (2011)
The Future of the Electric Grid (2011)
The Future of Solar Energy (2015)

Revision 1
Copyright © 2018 Massachusetts Institute of Technology.
All rights reserved.
Cover art by Sara Ferry, Nuclear Science and Engineering, MIT.

Study Participants
STUDY CO-CHAIRS
Jacopo Buongiorno, Co-Chair
Associate Department Head and TEPCO Professor,
Department of Nuclear Science andEngineering, MIT
Michael Corradini, Co-Chair
Professor Emeritus, Engineering Physics, Universityof Wisconsin-Madison

John Parsons, Co-Chair
Senior Lecturer, Sloan School of Management, MITDavid Petti, Executive Director
Laboratory Fellow, Nuclear Science and Technology
Directorate, Idaho National Laboratory; Visiting
Research Scientist, MIT

STUDY GROUP
Rasheed Auguste
Undergraduate Student, Department of Nuclear
Science and Engineering, MIT
Patrick Champlin
Master’s Student, Department of Nuclear Scienceand Engineering, MIT
Karen Dawson
PhD Candidate, Department of Nuclear Scienceand Engineering, MIT
Ze (Jenny) Dong
Undergraduate Research Opportunities Program
Student, Department of Nuclear Science andEngineering, MITCharles Forsberg
Principal Scientist, Department of Nuclear Scienceand Engineering, MIT
Andrew Foss
Energy Options Network
Eric Ingersoll
Energy Options Network
Joseph Lassiter
Senator John Heinz Professor of Management Practicein Environmental Management, Harvard Business
School, Retired
Richard Lester
Associate Provost and Japan Steel Industry Professor,
Office of the Provost, MIT

Jessica Lovering
Breakthrough Institute
Lucas Rush
Master’s Student, Department of Nuclear Scienceand Engineering, MIT
Nestor Sepulveda
PhD Candidate, Department of Nuclear Scienceand Engineering, MIT
Amy Umaretiya
Master’s Student, Technology and Policy Program, MIT
Robert Varrin
Dominion Engineering
Patrick White
Master’s Student, Department of Nuclear Scienceand Engineering, MIT
Dennis Whyte
Department Head and Hitachi America Professor,
Department of Nuclear Scienceand Engineering, MIT
Ka-Yen Yau
Undergraduate Student, Department of Nuclear
Science and Engineering, MIT

Advisory Committee
Philip Sharp (Chair)
Former President, Resources for the Future
Former U.S. Congressman
Jean-Pierre BenquePresident Emeritus, EDF Development Inc.
and EDF North America
Robert Budnitz
Project Scientist, Retired, Lawrence Berkeley
National Laboratory
James Del Favero
Co-Founder, Ardea Partners LLC
John DeutchInstitute Professor, MIT
Director Emeritus, CIA
Marvin Fertel
Retired President and Chief Executive Officer,
Nuclear Energy InstituteSusan Landahl
Senior Vice President, Exelon Corporation
William Magwood
Director, Nuclear Energy Agency
Former Commissioner, U.S. Nuclear Regulatory
Commission
Director Emeritus, U.S. Department of Energy,
Nuclear Energy OfficeKathryn McCarthy
Vice President for Research and Development,
Canadian National Laboratories
Richard Meserve
President Emeritus, Carnegie Institution for Science
Former Chairman, U.S. Nuclear Regulatory
Commission
Akira Omoto
Professor, Tokyo Institute of Technology
Advisor, Nuclear Risk Research Center
Former Director, Division of Nuclear Power,
International Atomic Energy Agency

Zack Pate
Chief Executive Officer and Chairman Emeritus,
Institute for Nuclear Power Operations andWorld Association of Nuclear Operators
Former U.S. Navy submarine commander
Bernard Salha
Senior Executive Vice President and Presidentof Research and Development, EDF
Michael Shellenberger
Founder and President, Environmental Progress
Dirk Smit
Vice President Research Strategy, Chief Scientist
Geophysics, Shell

Reviewers
Phillip Hildebrandt
Consultant

Mark Peters
Laboratory Director, Idaho National Laboratory

Sue Ion
Chairman, UK Nuclear Innovation Research
Advisory Board

Andrew Sherry
Chief Science and Technology Officer, UK National
Nuclear Laboratory

Scott Kemp
Associate Professor, Department of Nuclear Scienceand Engineering, MIT

Neil Todreas
Professor Emeritus, Department of Nuclear Scienceand Engineering, MIT

Andrew Klein
Professor Emeritus, Nuclear Science and Engineering,
Oregon State University

SUBJECT MATTER EXPERT REVIEWERS
George Apostolakis
Professor Emeritus, Department of Nuclear Scienceand Engineering, MIT
Former Commissioner, U.S. Nuclear Regulatory
Commission
Robert Armstrong
Director, MIT Energy Initiative; Chevron Professor ofChemical Engineering, Department of Chemical
Engineering, MIT
Rebecca Henderson
John and Natty McArthur University Professor,
Harvard Business School
Robert Hill
National Technical Director, Advanced Reactors,
Argonne National Laboratory
Dale Klein
Associate Vice Chancellor for Research for the UT
System and Reese Endowed Professorship inEngineering, University of Texas
Former Chairman, U.S. Nuclear Regulatory
Commission

Christopher Knittel
George P. Shultz Professor of Applied Economics, Sloan
School of Management; Director, Center for Energy
and Environmental Policy Research, MITPaul Joskow
Elizabeth & James Killian Professor of Economics
and Management, Emeritus, Department of
Economics, MIT
François Lévêque
Professor of Economics, MINES ParisTech
Steven Zinkle
Governor’s Chair Professor, Department of Nuclear
Engineering and Department of Materials Scienceand Engineering, University of Tennessee / Oak
Ridge National Laboratory

Table of Contents
Foreword and Acknowledgmentsix

Executive Summaryxi

Background and Overview

xv

Chapter One: Opportunities for Nuclear Energy

1

Chapter Two: Nuclear Power Plant Costs

31

Chapter Three: Advanced Reactor Technology Evaluation

59

Chapter Four: Nuclear Industry Business Models and Policies

95

Chapter Five: Nuclear Reactor Safety Regulation and Licensing

117

Appendices149

Abbreviations and Technical Terms

247

vii

viii

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDForeword and Acknowledgments
The MIT Future of Nuclear Energy in a CarbonConstrained World study is the eighth in the MIT
Energy Initiative’s “Future of” series, which aims
to shed light on a range of complex and important
issues involving energy and the environment.
A central theme is understanding the role oftechnologies that might contribute at scale inmeeting rapidly growing global energy demandin a carbon-constrained world. Nuclear power
could certainly play an important role, and it was
the subject of the first of these interdisciplinary
studies at MIT—the 2003 Future of Nuclear Power
report. More recent studies have looked at theroles of CO2 sequestration, natural gas, the electricgrid, and solar power. Following a 2009 update tothe original nuclear study, now is an appropriate
time to take a fresh look at nuclear, given advances
in inherently safer technologies, a sharpened
focus on the need to reduce CO2 emissions in theenergy sector, and challenges of cost and public
perceptions of safety.
The study is designed to serve as a balanced, factbased, and analysis-driven guide for stakeholders
involved in nuclear energy. Policy makers, utilities,
existing and startup energy companies, regulators,
investors, and other power-sector stakeholders
can use this study to better understand thechallenges and opportunities currently facing
nuclear energy in the U.S. and around the world.
The report distills results and findings from morethan two years of primary research, a review ofthe state of the art, and quantitative modelingand analysis.

The MIT Future of Nuclear Energy in a CarbonConstrained World study was supported by anumber of sponsors and was complemented
by a distinguished Advisory Committee andReview Team. We gratefully acknowledge thesupport of our major sponsor The Alfred P. Sloan
Foundation and important contributions from
Shell, Électricité de France (EDF), The David andLucile Packard Foundation, General Atomics, theAnthropocene Institute, MIT’s International Policy
Laboratory, Mr. Zach Pate, Mr. Neil Rasmussen,
and Dr. James Del Favero. We also thank the
Idaho National Laboratory, Dominion Engineering
Inc., Blumont Engineering Solutions (Paul Meierand his JuiceBox work for Chapter 1), Professor
Giorgio Locatelli from the University of Leeds(for his work on Megaprojects in Chapter 2), theBreakthrough Institute, and Lucid Strategy for
their generous in-kind contributions. We also wish
to acknowledge Professor Jessika Trancik and
Dr. James McNerny from the Institute for Data,
Systems, and Society at MIT for their valuable
input to the analysis of the cost breakdown ofnuclear power plants.
Our Advisory Committee members dedicateda significant amount of their time to participate
in meetings and to comment on our preliminary
analysis, findings, and recommendations.
We would especially like to acknowledge theefficient conduct of Advisory Committee meetings
under the able and experienced direction of
Chairman Philip R. Sharp. Our review teamunder the leadership of Professor Andrew Klein
provided valuable insight on our analysis, findings,
and recommendations.

Foreword and Acknowledgmentsix

The Study Team also wants to thank the following list of individuals who provided valuable input frominterviews and workshops conducted during the study:
Kev AdjemianLaurent Amice
Henry Aszklar
Scott Bailey
William Banholzer
Rita Baranwal
Jeff Bartelme
Elizabeth McAndrewBenavides
Gary Bergstrom
Michael Bielman
Richard Bradford
Jonathan Brown
Harlan Bowers
Bob Boyd
Vlad Bulović
Marcia Burkey
Nicolle Butcher
Jean-Marc CapdevilaCharles Chase
Doug Chapin
Ismail Cheng
Armond Cohen
Christopher Colbert
Justin Coleman

Marco Cometto
Jim CostedioDavid Darwin
Franck David
Michael Davidson
Paul DeLuca
Jacques de Toni
Dave Dilling
Sean Donnelly
Bradley Dunkin
Paul Erb
Ashley Finan
Michael Ford
Ben Frazier
Vince Gilbert
Mike Goff
Charles Gordon
Dustin Greenwood
Daniele Giuffrida
Abhinav Gupta
Puja Gupta
Kathryn Held
Ronald Henry
Bronwyn Hyland
Dan Ingersoll

Simon Irish
Ramzi Jammal
Rick Jefferys
Zabrina Johal
Lars Jorgensen
Jake Jurewicz
John Kelly
Jan-Horst Keppler
Efe Kurt
Albert Lafleur
Bob Langer
Philippe Larochelle
Christophe Levy
Ning LiFrank Ling
Robert Littles
Giorgio Locatelli
Eric Loewen
William Luyties
Audray Lyke
Ed Lyman
Iain Macdonald
Michel Maschi
Regis Matzie
Jan Mazurek

We wish to thank Carolyn Carrington for her
administrative support for all of the events,
meetings, and workshops as part of this study;
Marika Tatsutani for editing this report with greatskill and patience; Professor Robert C. Armstrong
for supporting this study in his role as Directorof the MIT Energy Initiative and as a reviewer;and MITEI Executive Director Martha Broad forproviding additional support and review.
MITEI staff provided administrative and financial
management assistance to this project. We would
particularly like to thank project manager Jennifer
Schlick; Francesca McCaffrey and Ivy Pepin forMatthew McKinziePaul Meier
Tom Miller
Phil Mills
Alexander Mishkin
Mike Myers
Steve Nance
Mark Nelson
Robert Nielsen
Marcus Nichol
Mike O’Connell
Frank O’Sullivan
Rory O’SullivanCharlie PainterBojan Petrovic
Jonathan Pellish
Mark Peres
Pedro Pereyra
Andrew Pinneke
Bruce Phillips
Neil Rasmussen
Ray Rothrock
Tony Roulstone
Jayant Sabnis
Tim Saeger

editing support; Debi Kedian, Carolyn Sinnes, andKayla Small for events support; and Emily Dahl,
MITEI Director of Communications. We would
also like to thank Allison Associates for layout
and figure design.
This report represents the opinions and views of
the researchers, who are solely responsible forits content, including any errors. The Advisory
Committee and the Reviewers are not responsible
for the findings and recommendations it contains,
and their individual opinions and views may differ
from those expressed herein.

Dedicated to the memory of our friend and colleague Mujid Kazimi.

x

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Arthur Samberg
Frank Saunders
Chris Schuh
Jacob Selzer
Daniel Shamblin
Farshid Shahrokhi
Santhosh Shankar
David Shropshire
James Stouch
Garrett Sonnenberg
Finis Southworth
Andrew Sowder
Marc Tannenbaum
Mathia Trojer
Jack Tuohy
Franz-Josef Ulm
Eric Van Abel
Jan Van Der Lee
Chris Vandervort
Jason Wang
Kevan Weaver
Brian Whitley
Don Wolf
Oscar Zamorano
Yaoli Zhang

Executive Summary
Harnessing the power of the atomic nucleus
for peaceful purposes was one of the mostastonishing scientific and technologicalachievements of the 20th century. It has benefitted
medicine, security, and energy. Yet, after a few
decades of rapid growth, investment in nuclear
energy has stalled in many developed countries
and nuclear energy now constitutes a meager 5%of global primary energy production.
In the 21st century the world faces the newchallenge of drastically reducing emissionsof greenhouse gases while simultaneously
expanding energy access and economic
opportunity to billions of people. We examined
this challenge in the electricity sector, which has
been widely identified as an early candidate fordeep decarbonization. In most regions, serving
projected load in 2050 while simultaneously
reducing emissions will require a mix of electricalgeneration assets that is different from thecurrent system. While a variety of low- or zerocarbon technologies can be employed in various
combinations, our analysis shows the potential
contribution nuclear can make as a dispatchable
low-carbon technology. Without that contribution,
the cost of achieving deep decarbonization targets
increases significantly (see Figure E.1, left column).
The least-cost portfolios include an important
share for nuclear, the magnitude of whichsignificantly grows as the cost of nuclear drops(Figure E.1, right column).
Despite this promise, the prospects for the
expansion of nuclear energy remain decidedly
dim in many parts of the world. The fundamental
problem is cost. Other generation technologies
have become cheaper in recent decades, while
new nuclear plants have only become costlier.
This disturbing trend undermines nuclear energy’s
potential contribution and increases the cost ofachieving deep decarbonization. In this study,
we examine what is needed to arrest and reversethat trend.

We have surveyed recent light water reactor(LWR) construction projects around the worldand examined recent advances in cross-cutting
technologies that can be applied to nuclear plant
construction for a wide range of advanced nuclear
plant concepts and designs under development. To
address cost concerns, we recommend:(1) An increased focus on using proven project/

construction management practices to increase
the probability of success in the execution anddelivery of new nuclear power plants.
The recent experience of nuclear construction
projects in the United States and Europe has
demonstrated repeated failures of construction
management practices in terms of theirability to deliver products on time and withinbudget. Several corrective actions are urgently
needed: (a) completing greater portions of thedetailed design prior to construction; (b) using
a proven supply chain and skilled workforce;(c) incorporating manufacturers and builders
into design teams in the early stages of thedesign process to assure that plant systems,
structures, and components are designed for
efficient construction and manufacturing torelevant standards; (d) appointing a single
primary contract manager with provenexpertise in managing multiple independent
subcontractors; (e) establishing a contracting
structure that ensures all contractors havea vested interest in the success of the
project; and (f) enabling a flexible regulatoryenvironment that can accommodate small,unanticipated changes in design andconstruction in a timely fashion.
(2) A shift away from primarily field construction of

cumbersome, highly site-dependent plants to more
serial manufacturing of standardized plants.
Opportunities exist to significantly reducethe capital cost and shorten the construction
schedule for new nuclear power plants. First,

Executive Summaryxithe deployment of multiple, standardized
units, especially at a single site, affords
considerable learning from the constructionof each unit. In the United States and Europe,
where productivity at construction sites has
been low, we also recommend expanded use
of factory production to take advantage of the
manufacturing sector’s higher productivity
when it comes to turning out complex
systems, structures, and components. The
use of an array of cross-cutting technologies,
including modular construction in factories
and shipyards, advanced concrete solutions(e.g., steel-plate composites, high-strength
reinforcement steel, ultra-high performance
concrete), seismic isolation technology, andadvanced plant layouts (e.g., embedment,
offshore siting), could have positive impacts
on the cost and schedule of new nuclear power
plant construction. For less complex systems,
structures, and components, or at sites whereconstruction productivity is high (as in Asia),
conventional approaches may be the lowestcost option.
It is important to emphasize the broad applicabilityof these recommendations across all reactor
concepts and designs. Cost-cutting opportunities
are pertinent to evolutionary Generation-III
LWRs, small modular reactors (SMRs), andGeneration-IV reactors.1 Without design
standardization and innovations in construction
approaches, we do not believe the inherent
technological features of any of the advanced
reactors will produce the level of cost reductions
needed to make nuclear electricity competitive
with other generation options.

designs. These concerns have led some countries
to renounce nuclear power entirely. To address
safety concerns, we recommend:(3) A shift toward reactor designs that incorporate

inherent and passive safety features.
Core materials that have high chemical andphysical stability, high heat capacity, negative
reactivity feedbacks, and high retention offission products, together with engineered
safety systems that require limited or no
emergency AC power and minimal externalintervention, will likely make operations simpler
and more tolerable to human errors. Suchdesign evolution has already occurred in some
Generation-III LWRs and is exhibited in newplants built in China, Russia, and the UnitedStates. Passive safety designs can reduce theprobability that a severe accident occurs, while
also mitigating the offsite consequences in theevent an accident does occur. Such designs
can also ease the licensing of new plants andaccelerate their deployment in developed anddeveloping countries. We judge that advanced
reactors like LWR-based SMRs (e.g., NuScale)and mature Generation-IV reactor concepts(e.g., high-temperature gas reactors andsodium-cooled fast reactors) also possess suchfeatures and are now ready for commercial
deployment. Further, our assessment of the
U.S. and international regulatory environmentssuggests that the current regulatory system
is flexible enough to accommodate licensingof these advanced reactor designs. Certain
modifications to the current regulatory
framework could improve the efficiency andefficacy of licensing reviews.

In addition to its high cost, the growth of nuclear
energy has been hindered by public concerns
about the consequences of severe accidents(such as occurred at Fukushima, Japan in 2011)
in traditional Generation-II nuclear power plant1xii

 eactor designs are frequently classified into four generations. The first commercial nuclear reactors built in theRlate 1950s and 1960s are classified as Generation-I systems. Generation-II systems include commercial reactorsthat were built from 1970 to 1990. Generation-III reactors are commercial designs that incorporate evolutionary
improvements over Generation-II systems. Generation-IV is the classification used to describe a set of advanced
reactor designs that use non-water coolants and are under development today.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Figure E.1: (left) Average system cost of electricity (in $/MWhe) and (right) nuclear installed capacity (% of peak demand)in the New England region of the United States and the Tianjin-Beijing-Tangshan (T-B-T) region of China for different carbon
constraints (gCO2/kWhe) and three scenarios of various available technologies in 2050: (a) no nuclear allowed, (b) nuclear
is allowed at nominal overnight capital cost ($5,500 per kWe for New England and $2,800 per kWe for T-B-T), and (c) nuclear
is allowed with improved overnight capital cost ($4,100 per kWe for New England and $2,100 per kWe for T-B-T)

Nuclear - None

Nuclear - Nominal Cost

New England, United States

Nuclear - Low Cost

Nuclear - Nominal

250

Nuclear Installed Capacity(% Peak Demand)

Average Generation Cost ($/MWhe )New England, United States

200
150
100
50
0

500

100

50
10
Emissions (g-CO2/kWh e )

1

60
50
40
30
20
10
0

500

Nuclear - Nominal Cost

Nuclear - Nominal

250
200
150
100
50
0

500

100

100
50
10
Emissions (g-CO2/kWh e )1

T-B-T China
Nuclear - Low Cost

Nuclear Installed Capacity(% Peak Demand)

Average Generation Cost ($/MWhe )T-B-T China
Nuclear - None

Nuclear -Low Cost

70

50
Emissions (g-CO2/kWhe )10

1

Nuclear -Low Cost

100
80
60
40
20
0

500

100
50
10
Emissions (g-CO2/kWh e )1Simulations were performed with an MIT system optimization tool called GenX. For a given power market the required inputs include
hourly electricity demand, hourly weather patterns, economic costs (capital, operations, and fuel) for all power plants (nuclear, wind andsolar with battery storage, fossil with and without carbon capture and storage), and their ramp-up rates. The GenX simulations wereused to identify the electrical system generation mix that minimizes average system electricity costs in each of these markets. The costescalation seen in the no-nuclear scenarios with aggressive carbon constraints is mostly due to the additional build-out and cost of energy
storage, which becomes necessary in scenarios that rely exclusively on variable renewable energy technologies. The current world-averagecarbon intensity of the power sector is about 500 grams of CO2 equivalent per kilowatt hour (g/kWhe); according to climate change
stabilization scenarios developed by the International Energy Agency in 2017, the power-sector carbon intensity targets to limit global
average warming to 2°C range from 10 to 25 g/kWhe by 2050 and less than 2 g/kWhe by 2060.

Executive Summaryxiii

Lastly, key actions by policy makers are alsoneeded to capture the benefits of nuclear energy:(4) Decarbonization policies should create a levelplaying field that allows all low-carbon generation
technologies to compete on their merits.

government should provide appropriate
supervision and support—including safety
protocols, infrastructure, environmental
approvals, and fuel-cycle services—and should
also be directly involved with all testing.
(6) Governments should establish funding programs

Investors in nuclear innovation must see
the possibility of earning a profit based on
selling their products at full value, whichshould include factors such as the value of
reducing CO2 emissions that are external
to the market. Policies that foreclose a rolefor nuclear energy discourage investment in
nuclear technology. This may raise the costof decarbonization and slow progress toward
climate change mitigation goals. Incorporating
CO2 emissions costs into the price of electricity
can more equitably recognize the value to all
climate-friendly energy technologies. Nuclear
generators, both existing plants and the newbuilds, would be among the beneficiaries of alevel, competitive playing field.
(5) Governments should establish reactor sites

where companies can deploy prototype
reactors for testing and operation oriented toregulatory licensing.
Such sites should be open to diverse reactor
concepts chosen by the companies thatare interested in testing prototypes. The

xiv

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDaround prototype testing and commercial
deployment of advanced reactor designs using
four levers: (a) funding to share regulatory
licensing costs, (b) funding to share researchand development costs, (c) funding for theachievement of specific technical milestones,and (d) funding for production credits to reward
successful demonstration of new designs.
Many more findings emerged in the course of theresearch undertaken for this study. A detailed
discussion of these findings is contained in theoverview and main body of the study report,
which is organized into five major topic areas(with corresponding chapter titles): Opportunities
for Nuclear Energy, Nuclear Power Plant Costs,
Advanced Reactor Technology Evaluation, Nuclear
Industry Business Models and Policies, andNuclear Reactor Safety Regulation and Licensing.

Background and Overview
THE BIG PICTURE

climate change is among the central challenges
confronting humankind in the 21st century. This
study focuses on the electric power sector,
which has been identified as an early target
for deep decarbonization. In the foreseeable
future, electricity will continue to come primarily
from a mix of fossil fuels, hydropower, variable
renewables such as solar and wind, and nuclear
energy (U.S. Energy Information Administration
2017). At present nuclear energy supplies about
11% of the world’s electricity and constitutes
a major fraction of all low-carbon electricity
generation in the United States, Europe, andglobally (Figure 2). Nuclear energy’s future role,
however, is highly uncertain for several reasons:chiefly, escalating costs and, to a lesser extent, thepersistence of historical challenges such as spent
fuel disposal and concerns about nuclear plantsafety and nuclear weapons proliferation.

Access to electricity plays a vital role in improving
standards of living, education, and health. This
relationship is illustrated by Figure 1, which locatesvarious countries according to their score on
the Human Development Index, a well-known
metric of economic and social development,
and per capita electricity use. As countries
develop, electricity use tends to rise; according
to current forecasts, electricity consumption
in developing non-OECD (Organisation for
Economic Co-operation and Development)
countries is expected to grow 60% by 2040,
whereas worldwide use is expected to grow 45%
in the same timeframe (U.S. Energy Information
Administration 2017).
Expanding access to energy while at the sametime drastically reducing the emissions ofgreenhouse gases that cause global warming andHuman Development Index vs. Electricity Use

Figure 1: Human Development Index versus per capita electricity consumption for different countries
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Background and Overview

xv

THE NUCLEAR ENERGY LANDSCAPE
Since MIT published its first Future of Nuclear
Power study (Deutch, et al. 2003), the context
for nuclear energy in the United States andglobally has changed dramatically for the worse.
Throughout most of the 2000s, the U.S. fleet of
nuclear power plants was highly profitable: theircapital costs had been largely amortized overprevious decades and their production costs were
low compared to the relatively high cost of fossil
and renewable alternatives. As utilities sought tomaximize the value of their nuclear assets, theyembarked on a flurry of market-driven nuclear
power plant purchases, power uprates, and license
extensions. The situation changed quickly after
2007, as large quantities of inexpensive shalenatural gas became available in the United States
and the Great Recession depressed electricity
demand and prices. Since then, nuclear power
plants in the United States have become steadily
less profitable and the industry has witnesseda wave of plant closures. Two recent examples
include the Kewaunee plant in Wisconsin, whichshut down in 2013 (Dotson 2014), and the Fort
Calhoun plant in Nebraska, which shut downin 2016 (Larson 2016). Both plants shut downbecause they could not compete with cheaper
generation options. Falling natural gas prices in
Europe and Asia have put more economic pressure
on nuclear power in those regions also.

While the U.S. nuclear industry remains
exceptionally proficient at operating the existing
fleet of power plants, its handling of complex
nuclear construction projects has been abysmal,
as exemplified by the mismanagement ofcomponent-replacement projects at the San
Onofre (Mufson 2013) and Crystal River (Penn
2013) plants, which led to the premature closureof both plants in 2013. Other projects, including
the troubled Vogtle (Proctor 2017) and V. C.
Summer (Downey 2017) expansion projects, haveexperienced soaring costs and lengthy schedule
delays. In the case of Vogtle and V.C. Summer,
costs doubled and construction time increasedby more than three years, causing the reactor
supplier Westinghouse (Cardwell and Soble
2017) to declare bankruptcy (Westinghouse
only began emerging from Chapter 11 protection
in 2018) (Hals and DiNapoli 2018). The V. C.
Summer project was ultimately abandoned in 2017
(Plumer 2017).
New nuclear plant construction projects by
French reactor suppliers Areva and EDF at
Olkiluoto (Finland) (Rosendahl and Forsell 2017),
Flamanville (France) (Reuters 2018), and Hinkley
Point C (United Kingdom) (BBC News 2017),
have suffered similarly severe cost escalation anddelays. Clearly, the goal of deploying new nuclear
power plants at an overnight capital cost of lessthan $2,000 per electric kilowatt, as claimed

Figure 2: Share of carbon-free electricity sources in several major economies and worldwide
80
70
60
50

%

40
30
20
10
0

2015 World2015 US

NuclearHydro

2015 China

Solar,Wind,Geo,etc.

(International Energy Agency 2017)

xvi

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

2015 EU

by the North American and European nuclear
industries in the 2000s (Winters, Corletti, andThompson 2001) (World Nuclear Association2008), turned out to be completely unrealistic.
New nuclear plant construction (International
Atomic Energy Agency 2017) has continued ata steady rate in countries like South Korea, China,
and Russia; construction has also recently started
in the Middle East. Many of these projects havebeen completed more or less on time, and likely atsignificantly lower cost than comparable projects
in the West, although it is often challenging to
independently validate the cost figures publishedin these countries.
In 2011, the combined effects of a massive
earthquake and tsunami triggered an accident
at the Fukushima Daiichi nuclear power plantin Japan and led to an unfortunate decision by
Japanese authorities to force the evacuationof nearly 200,000 people from the region
surrounding the site. This event renewed publicconcerns about the safety of nuclear installations.
Although the radiological consequences of theaccident have been minimal (United Nations
Scientific Committee on the Effects of Atomic
Radiation 2017), by 2012 the entire nuclear fleet
in Japan was temporarily shut down, and only ahandful of nuclear plants are currently back online
in that country. In the wake of Fukushima, fivecountries (Germany, Switzerland, Belgium, Taiwan,
and South Korea) announced their intention
to ultimately phase out nuclear energy (World
Nuclear Association 2017), though to date only
Germany has taken immediate action toward
actually implementing this policy.
Against this bleak backdrop, some opportunities
have nonetheless emerged for the nuclear
energy industry. Heightened awareness of thesocial, economic, and environmental risks ofclimate change and air pollution has provided
a powerful argument for maintaining andpotentially increasing nuclear energy’s shareof the global energy mix (Hansen, et al. 2015).
Private investors appear interested in developing
and deploying advanced reactor technologies(Brinton 2015), even as the readiness of thesetechnologies has significantly increased in

the past 15 years (ANL-INL-ORNL 2016)(Generation-IV International Forum 2014). Finally,
there seems to be bipartisan support in the U.S.
Congress for renewed American leadership incommercializing new nuclear technology (115th
U.S. Congress 2017–2018).

THIS STUDY
In light of the important changes that haveoccurred since MIT’s 2003 Future of Nuclear Power
report and the 2009 update to the study, coupledwith the existential challenges that now confront
the nuclear industry, we concluded that it wastime to conduct a new interdisciplinary study
analyzing the future prospects of nuclear energy
in the United States and internationally.
Based on the findings that emerged from thisstudy, we contend that, as of today and for
decades to come, the main value of nuclear energy
lies in its potential contribution to decarbonizing
the power sector. Further, we conclude that costis the main barrier to realizing this value. Without
cost reductions, nuclear energy will not play asignificant role.
Nuclear energy does provide other benefits: it
reduces other types of air pollution associatedwith electricity production; in addition, it
contributes to fuel diversification and grid stability,
has low land requirements, and creates well-paidjobs. These benefits are important in certain
contexts; for example, nuclear energy may beattractive in countries that do not have enoughland or suitable weather patterns for large-scale
deployment of renewables, or in countries thatare seeking to reduce coal use to improve air
quality, or in countries that are concerned about
the security and reliability of their energy supply.
However, we believe that the primary, generally
applicable attribute of nuclear energy that may
justify its future growth on a global scale is its
low-carbon nature. As such, we posit that special
consideration should be given to preserving theexisting nuclear power plant fleet as a bridge to acarbon-constrained future (as recognized in recent
legislation adopted by the U.S. states of New York
(Larson 2016), Illinois (Anderson 2016), andBackground and Overview

xviiNew Jersey (Sethuraman 2018)), and to retaining
essential expertise for operating the nuclear
systems of the future.
We draw important lessons from a representative
set of recent and ongoing nuclear construction
projects worldwide and identify best practices thatmust be applied to any future projects. Further, weanalyze the cost drivers for new nuclear builds—
in particular, the relative importance of site
preparation, civil works, equipment, equipment
installation, engineering, and financing costs. We
examine a broad range of technology innovations,from new construction techniques to advanced
concrete solutions and from robotics to advanced
manufacturing, in the quest to identify cost
reduction opportunities for new nuclear.
We evaluate the benefits and challenges ofadvanced reactor technologies, defined here as
light-water-cooled small modular reactors (SMRs)
and non-water-cooled reactors (Generation-IV
systems). These systems incorporate inherent
safety features and passive safety systems
that may simplify operations, reduce theprobability of severe accidents, and limit theoffsite consequences of such accidents, thus
potentially broadening the number of suitablesites for nuclear power plants. We note that some
Generation-III light water reactor (LWR) designs,
such as the AP1000 and economic simplified
boiling water reactor (ESBWR), have alreadyadopted this approach. With the increasing roleof variable renewables on the grid, a certain
flexibility in operations is expected from all
dispatchable power generators. Nuclear plants
were traditionally designed for baseload operation,but, as has been recently demonstrated in Europe
and the United States (Jenkins, et al. 2018),
nuclear plants can adapt to provide load-following
generation and many advanced reactor concepts
are being designed for that capability as well.
Advanced reactors are also expected to utilize
simpler and more compact designs to reduce costand capture new markets such as process heat forindustry. This study critically assesses such claims
and expectations.

xviii

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDHistorically, time-to-market and development
costs for new nuclear reactors have been too high,making them fundamentally unattractive to private
investors, and leading some to advocate for directgovernment involvement in the development ofthese technologies (Secretary of Energy Advisory
Board 2016). Prototype Generation-IV systems
are currently being explored by the governmentsof several countries, including China, which has
deployed high-temperature gas-cooled reactors(HTGRs) (Zhang, et al. 2016), Russia (Digges
2016), and India (Patel 2017), both of which have
deployed sodium-cooled fast reactors (SFRs).
We examine the regulatory framework for theseadvanced reactor designs to determine if there are
any impediments to licensing them in the UnitedStates and to identify opportunities for making
the regulatory framework for these designs more
efficient. We also assess options for shortening
the time to commercialization for certain lessmature Generation-IV reactors (e.g. molten salt,
gas-cooled fast, and lead-cooled fast reactors),
and discuss what role the U.S. government andits national laboratories are likely to play in thatprocess. Finally, we review and recommend
specific government policies that would put all
low-carbon energy technologies on an equal
footing, which we deem essential to incentivizing
private investment in new nuclear capacity.
This study does not address the disposal ofradioactive waste (or, more properly, spent
nuclear fuel) or proliferation risks. While theseissues are universally considered barriers to the
expansion of nuclear energy use, the politicaldimensions of finding solutions to waste disposal
and managing proliferation risks far outweigh thetechnical challenges. We have reviewed recent
studies of the nuclear fuel cycle that focused on
the management and disposal of spent fuel (BlueRibbon Commission on America’s Nuclear Future2011) (Kazimi, et al. 2011) (Wigeland, et al.
2014) and have found their recommendations
to be valid. Briefly, there exist robust technicalsolutions for spent fuel management, such as
interim storage in dry casks and permanent
disposal in geological repositories with excavatedtunnels or deep boreholes—the greater difficulty,
historically, has been siting such facilities. Butthe evidence suggests that these solutions
can be implemented through a well-managed,consensus-based decision-making process, as has
been demonstrated in Finland (Fountain 2017)
and Sweden (Plumer 2012). Domestically, the U.S.
government should follow these examples andswiftly move on the recommendations for spent
fuel management that have been put before it.
The question of nuclear materials proliferation
is more complex. Adopting certain fuel cycle
facilities such as international fuel banks andcentralized spent fuel repositories can makethe civilian nuclear fuel cycle unattractive as apath to gaining nuclear weapons materials orcapability. At the same time, there is a desire on
the part of established nuclear countries to supply
nuclear technologies to newcomer countries, bothbecause it constitutes a business opportunity andas a means to gain considerable, decades-longgeopolitical influence in key regions of the world.
Currently Russia and, to a lesser extent, China
are aggressively pursuing opportunities to supply
nuclear energy technology to other countries.
Some have argued that if the United States wishes
to pursue such opportunities and advance othergeo-political objectives while simultaneously
sustaining the non-proliferation and safety
norms it has advocated around the world, it has
a compelling interest in maintaining a robust
domestic nuclear industry (Moniz 2017) (Center
for Strategic and International Studies 2018)(Aumeier and Allen 2008).
This study is organized into five chapters that
focus on several key issues:
1.

Opportunities for Nuclear Energy

2.

Nuclear Power Plant Costs

3.

Advanced Reactor Technology Evaluation

4.

Nuclear Industry Business Models and Policies

5.

Nuclear Reactor Safety Regulationand Licensing

The remainder of this overview briefly describes
each chapter and summarizes findings andrecommendations. A full discussion of theanalyses and considerations that led to thesefindings and recommendations can be foundin the chapters that comprise the main body of
the report.

SUMMARY OF FINDINGS AND
RECOMMENDATIONS
Chapter 1: Opportunities for Nuclear Energy
We evaluate market opportunities for nuclear
energy in electricity generation and otherenergy products in the United States and othercountries. We also explore in detail how imposing
a carbon constraint affects the optimal electricity
generation mix in different regions of the world.
Finding: The cost of new nuclear plants is high,and this significantly constrains the growth of
nuclear power under scenarios that assume‘business as usual’ and modest carbon emission
constraints. In those parts of the world where acarbon constraint is not a primary factor, fossil
fuels, whether coal or natural gas, are generally alower cost alternative for electricity generation.
Under a modest carbon emission constraint,
renewable generation usually offers a lower
cost alternative.
As the world seeks deeper reductions in electricity
sector carbon emissions, the cost of incremental
power from renewables increases dramatically.
At the levels of ‘deep decarbonization’ that havebeen widely discussed in international policy
deliberations—for example, a 2050 emissions
target for the electric sector that is well below
50 grams carbon dioxide per kilowatt hour ofelectricity generation (gCO2/kWh)—including
nuclear in the mix of capacity options helps tominimize or constrain rising system costs, whichmakes attaining stringent emissions goals more
realistic (worldwide, electricity sector emissions
currently average approximately 500 gCO2/kWh).
Lowering the cost of nuclear technology can help
reduce the cost of meeting even more modest
decarbonization goals (such as a 100 gCO2/kWhemissions target).

Background and Overview

xixChapter 2: Nuclear Power Plant Costs
We analyze attributes for successful nuclear build
projects and cost drivers for those projects. Then
we review a range of enabling technologies (suchas innovations in construction approaches) andexamine their ability to substantially reduce thecost of new nuclear power plants.
Finding: New nuclear plants are not a profitable

investment in the United States and Western
Europe today. The capital cost of building theseplants is too high.
Finding: Successful nuclear builds tend to have thefollowing attributes:a) Completion of needed portions of the designprior to start of construction,1b) Development of a proven supply chain

for nuclear steam supply system (NSSS)
components and access to a skilledlabor workforce,1c) Inclusion of fabricators and constructors in thedesign team to ensure that components canbe manufactured and structures can be built torelevant standards,d) Appointment of a single primary contract

manager with proven expertise in managing
multiple independent subcontractors,e) Establishment of a contracting structure inwhich all contractors (and subcontractors) havea vested interest in the success of the project,f) Adoption of contract administrative

processes that allow for rapid andnon-litigious adjustments to unanticipatedchanges in requirements or subcontractor
performance, andg) Operation in a flexible regulatory environmentthat can accommodate small, unanticipatedchanges in design and construction ina timely fashion.

1xx

Recommendation: Focus on using proven projectand construction management practices toincrease the probability of success in the execution
and delivery of new nuclear power plants.
Finding: Cost reduction efforts need to be focused

not on the NSSS design or the specific reactor
technology but on (a) improvements in how theoverall plant is constructed (or delivered to thesite), and (b) ways to accelerate the construction
process to reduce interest costs during this period.
Finding: Modularization, when used judiciously

in nuclear plant construction and component
fabrication, could be a viable cost-reduction
strategy in advanced reactor designs. In addition,
our examination suggests that (a) countries withhigh labor rates and low productivity have stronger
incentives to use modular construction in factories
and shipyards to reduce labor requirements(especially for very expensive labor at the plantsite), and (b) if the factories and shipyards used
to produce components are located in countries
with low labor rates and high productivity,
overall savings could be substantial. However, forstructures, systems, and components that are lesscomplex, onsite assembly may still be the lessexpensive option.
Finding: New reactor buildings and structuresneed to be optimized, taking into account boththe amount of material and the amount of labornecessary for fabrication and installation in aneffort to minimize the overall cost of commodities
used in plant construction as much as possible.
Finding: Civil engineering activities in supportof new reactor construction can be performed ina modular fashion by employing structures thatare designed to be manufactured and assembled
using advanced concrete techniques when suchan approach is less expensive than conventional‘stick building.’
Finding: Standardization (especially at multi-unit
sites), embedment below grade or underground(or, alternatively, offshore siting), and seismic
isolation can reduce construction costs andimprove safety and security.

Note that attributes (a) and (b) are typical issues for first-of-a-kind projects.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDChapter 3: Advanced Reactor Technology
Evaluation
We review the technical characteristics ofadvanced reactor technologies that may beconsidered in the future. Our evaluation focuseson important attributes including safety,
operability and maintainability, and potential range
of applications as enabled by specific featuresof the different reactor technologies. We also
assess technical readiness and discuss the costs,
lead-times, technical challenges, and financial
requirements for developing and commercializing
different advanced reactor systems.
Finding: In advanced reactors, the combinationof fuel, coolant, and moderator results in a set ofcore materials that has high chemical and physicalstability, high heat capacity, negative reactivity
feedbacks, and high retention of fission products.
In addition, these systems include engineered
safety systems that require no emergency AC
power and minimal external interventions. This
type of design evolution has already occurred inadvanced LWRs and is exhibited in new plants
built in China, Europe, and the United States.
These design attributes will make plant operations
much simpler and more tolerable to humanerrors, thereby reducing the probability thatsevere accidents occur and drastically reducing
offsite consequences in the event that they do.
Their improved safety characteristics can also
make licensing of new nuclear plants easier andaccelerate their deployment in developed anddeveloping countries.
Finding: Technology advances in plant design,

not in the reactor, hold the greatest promise for
reducing capital cost. All the broadly discussed
reactor concepts, including incumbent LWR
technology and several of the Generation-IV
designs, can potentially exploit many of theseadvances. The challenge for any proposed plantdesign is to achieve the radical cost reductions
needed to make a new nuclear plant competitivein the on-grid electricity market.
Finding: Traditionally, early-stage costestimates have been significantly biased toward
underestimating costs and hence have been
unreliable predictors of the eventual cost of a given

nuclear technology once its technical readinessincreases and the reactor design matures.
Nevertheless, our assessment of advanced reactor
systems suggests that these systems have thepotential to exploit inherent and passive safety
features to improve overall safety and operation.
These systems have promise, but their economic
potential is not yet proven. A commitment to
explore and test advanced reactor technologies
may provide significant economic benefit for
future electricity systems.
Recommendation: Future research, development,
and demonstration (RD&D) funding should
prioritize reactor designs that are optimized
to substantially lower capital costs, including
construction costs. Innovations in fast
reactors that are advertised on the basis offuel cycle metrics are unlikely to advancecommercial deployment.
Finding: Each advanced reactor system is at adifferent level of technical maturity and as suchrequires a number of key technology development
activities to be completed before it can becommercialized. The overall time needed to reachcommercialization depends on the technicalmaturity of the concept and prior experience
with the specific reactor technology involved.
More mature concepts, such as the advanced
small modular reactor (SMR) design being
marketed by NuScale, a sodium fast reactor, and a
modular high temperature gas-cooled reactor, aretechnically ready for commercialization by 2030.
Less mature reactor concepts, including lead fast
reactors, gas-cooled fast reactors, and molten salt
systems, however, would not be expected to reachcommercialization before 2050 if the traditional
approach to nuclear development is followed.
Recommendation: A more innovative approachto deployment is needed to advance lessmature advanced reactor designs. Under thisnew paradigm, proof of concept and proof of
performance would be demonstrated using asingle reactor that would be: (a) designed at fullscale to reduce scale-up risks, (b) designed withconservative thermo-mechanical margins, (c)licensed under the prototype rule developed by
the U.S. Nuclear Regulatory Commission (NRC) to
provide flexibility and reduce the burden of proof

Background and Overview

xxi

typically expected in licensing, and (d) sited ona remote U.S. Department of Energy (DOE) site
as an extra precaution to remove some safety
constraints on the design and allow for integral
testing. Using this new paradigm, developmentof the least mature systems could be accelerated
and the expected timeframe for commercial
deployment could be moved up to the midto late-2030s.

Chapter 4: Nuclear Industry Business Models
and Policies
We examine the current market for nuclear energy
in the United States and worldwide and explore
the market challenges that currently confront theexisting nuclear fleet. We then discuss the policychanges and possible business models that areneeded to accelerate the deployment of advanced
reactor systems.
Finding: In most cases, existing nuclear is acost-efficient provider of low-carbon electricity.
Premature closures of existing plants undermine
efforts to reduce carbon dioxide and otherpower sector emissions and increase the cost ofachieving emission reduction targets.
Finding: A major source of revenue deficiency

for nuclear generators today is the fact that they
are not fully compensated for their low-carbon
attributes. Ameliorating this deficiency wouldchange nuclear energy’s market position andconserve much existing nuclear capacity.
Recommendation: Public policies to advancelow-carbon generation should treat alltechnologies comparably. There should be nodiscrimination against nuclear energy.
Finding: There is little evidence that revenue
deficiencies for existing nuclear power plants
in the United States are due to ‘attributes’ thatare being systematically mispriced by wholesale
electricity market rules, aside from the failure toproperly price nuclear energy’s climate benefits.
Finding: Discrimination against nuclear as
a low-carbon energy source is not rooted intechnical issues of electricity market design.
Rather, it is primarily rooted in public attitudes
towards nuclear. These public attitudes

xxii

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDtranslate into discriminatory public policies
outside of wholesale market rules, which in turnshape profitability.
Recommendation: Achieving deep reductions in
global carbon emissions will require a dramatic
restructuring of the technologies deployed in
the electricity industry. Constant adjustments
will be needed to align market rules to the newtechnologies being deployed. The nuclear energy
industry has a stake in ongoing research to assurethat changes in market design are consistent withthe deployment of advanced nuclear systems.
Recommendation: The implementation of apolitically durable solution for the managementof spent nuclear fuel would greatly facilitate
significant investment in new nuclear technologies.
Finding: Private business is well suited to driving

innovations that would lead to new reactor designs
with radically lower capital costs. To harness
this capability, the private sector must make thetechnology choices and supply the major capital
investments. Private companies must enjoy thepotential for profit and also bear the risk of loss.
Recommendation: Governments should establish
reactor parks where companies can site prototype
reactors to conduct testing and operations
oriented to licensing. These parks should be
open to diverse reactor concepts chosen by
the companies. Governments should provide
appropriate supervision and support–including
safety protocols, infrastructure, environmental
approvals, and fuel cycle services–and should bedirectly involved with all testing.
Recommendation: Governments should
establish programs to fund prototype testing
and commercial deployment of new, advanced
reactor designs. These programs should
focus on four levers for advancing progress
toward commercialization:
1.

Funding to share R&D costs related to moving
new reactor designs toward the construction ofa demonstration reactor,

2. Funding to share licensing costs for

new demonstration reactors andcommercial designs,

3. Funding for milestone payments forconstruction and operation of a demonstration
reactor, and4. Funding for production credits to reward

successful demonstration of new designs.

Chapter 5: Nuclear Reactor Safety Regulationand Licensing
We review the regulatory structure for nuclear
energy in the United States and around theworld and assess the ability of current regulatory
structures and approaches to accommodate thelicensing of advanced nuclear reactor systems.
Finding: Regulatory agencies around the world

have adopted basic principles similar to thosedescribed in the policies of the International
Atomic Energy Agency (IAEA) and in U.S. NRC
regulations, though they vary in their detailed
application of these policies and principles—for
example, with respect to required burden of proof.
While significant cultural, social, and politicaldifferences may exist between countries, thefundamental basis for assessing the safety of
nuclear reactors is fairly uniform among countries
with established nuclear power programs.
Recommendation: Regulatory requirements foradvanced reactors should be coordinated andaligned internationally to enable international
deployment of commercial reactor designs,
and to standardize and ensure a high level ofsafety worldwide. National differences in safety
regulations due to accepted cultural practices
make it difficult to develop a universally
accepted regulatory licensing regime. But certain
basic standards for nuclear safety should bemaintained internationally due to the far-reachingenvironmental and social/political effects ofnuclear plant operation. Initial international
agreement on specific topics (e.g., station blackout
resiliency) and joint licensing evaluations could
advance discussions about undertaking reciprocal
reactor design evaluations between nations or
standardizing international safety requirements.
Finding: A wide variety of pathways and strategies
are available for licensing new reactors (including
advanced reactors) in the United States. These

include using existing regulatory processes suchas topical reports, standard design approvals,
standard design certification, and either Part 50 orPart 52 licensing.
Recommendation: While current regulatory

structures have sufficient flexibility to allow fortechnology- or reactor-specific licensing pathways,
the U.S. NRC should continue to move toward
the use of performance-based and risk-informed
design criteria for new reactors.
Recommendation: In the United States, the NRC

should test its advanced reactor licensing process
in the next few years to identify unanticipatedlicensing hurdles and to train NRC staff.
Finding: In the United States, the NRC currently
has the regulatory processes available toimplement a phased licensing approach foradvanced reactors—thus no new formal regulatory
processes are needed. Use of phased licensing
processes, however, may increase the total cost,time, and uncertainty related to advanced reactor
licensing. Applicants must determine on a caseby-case basis which licensing approaches best
suit their project and should work with the NRC tocreate design-specific licensing plans that use themost appropriate set of regulatory tools to achieve
desired outcomes from the licensing process.
Finding: The U.S. NRC’s prototype rule can provide
an alternative pathway for licensing advanced
nuclear reactor designs.
Recommendation: The U.S. NRC should clarify
its prototype rule and licensing pathway to allow
for more rapid licensing of prototype reactors
without excessive regulatory burden. While
additional safety features may be required
to license a prototype reactor, regulators andlicense applicants should agree to conditions(experimental tests and data) that would allow forthese features to be removed in future plants. The
prototype licensing pathway should be available toall reactor technologies.
Finding: Inconsistency in the design margins
required by different codes and standards canresult in relative underdesign or overdesign ofstructures, systems, and components.

Background and Overview

xxiii

Recommendation: Consensus codes used in thedesign and construction of nuclear power plants
should be re-evaluated in terms of their efficacy inensuring safety. The nature of system interactionsin advanced reactor designs may fundamentallydiffer from previously operated reactor designs.
Existing consensus codes should be reviewed
so that overlapping standards are properly
harmonized. This harmonization will both reduce
the regulatory burden and help to ensure safe
operation for advanced reactor designs.
Finding: Adequate funding for advanced

reactor licensing efforts is necessary to ensure
timely licensing actions. In the United States,
funding for such licensing development efforts
is currently limited and comes from operating
nuclear facilities.
Recommendation: The U.S. government should
provide funding for advanced reactor regulation
outside the NRC’s 90% fee recovery model toensure that sufficient resources are available
when needed. At the same time, the nuclear
energy industry must communicate regulatory
function and research needs with key U.S. entities,
including the NRC, DOE, and Congress, to ensurethat adequate funding is appropriated.

xxiv

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDCONCLUSION
In summary, this study delivers four key messages:• The central opportunity for nuclear energy overthe next several decades is tied to its potential
contribution to decarbonizing the power sector;• The central challenge to realizing thiscontribution is the high cost of new
nuclear capacity;• There are ways to reduce nuclear energy’s cost,which the industry must pursue aggressively
and expeditiously;• Government help, in the form of well-designed
energy and environmental policies andappropriate assistance in the early stages of
new nuclear system deployment, is needed torealize the full potential of nuclear.

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Rosendahl, J., and T. Forsell. “Areva’s Finland reactor
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October 9, 2017. https://www.reuters.com/article/
us-finland-nuclear-olkiluoto/arevas-finland-reactor-tostart-in-2019-after-another-delay-idUSKBN1CE1ND.
Sethuraman, R. N. “New Jersey Senate, Assembly
passes nuclear subsidy bill.” Reuters, April 12, 2018.
https://www.reuters.com/article/
pseg-nuclear-new-jersey-subsidies/
update-1-new-jersey-senate-assembly-passes-nuclearsubsidy-bill-idUSL1N1RP2EN.
U.S. Department of Energy. 2016. Secretary of Energy
Advisory Board Report of the Task Force on the Futureof Nuclear Power.
U.S. Energy Information Administration. 2017.
“International Energy Outlook.” https://www.eia.gov/
outlooks/ieo/pdf/0484(2017).pdf.
United Nations Development Programme. 2017.
“Human Development Index.” Human Development
Reports. http://hdr.undp.org/en/content/
human-development-index-hdi.
United Nations Scientific Committee on the Effects ofAtomic Radiation. 2017. “Developments since the 2013
UNSCEAR report on the levels and effects of radiation
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white paper to guide the Scientific Committee’s future
programme of work.” New York.
Wigeland, R., et al. 2014. “Nuclear Fuel Cycle Evaluationand Screening—Final Report, INL/EXT‑14‑31465,
FCRD-FCO-2014-000106.”
Winters, J. W., M. M. Corletti, and M. Thompson.
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9th International Conference On Nuclear Engineering(ICONE-9). Nice, France.

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THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDWorld Nuclear Association. 2008. “The Economics
of Nuclear Power.” Information Papers, World Nuclear
Association.
World Nuclear Association. 2017. Nuclear Powerin Belgium. http://www.world-nuclear.org/
information-library/country-profiles/countries-a-f/
belgium.aspx.
—. 2017. Nuclear Power in Germany.
http://www.world-nuclear.org/information-library/
country-profiles/countries-g-n/germany.aspx.
—. 2017. Nuclear Power in South Korea.
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country-profiles/countries-o-s/south-korea.aspx.
—. 2017. Nuclear Power in Switzerland.
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country-profiles/countries-o-s/switzerland.aspx.
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Engineering 2 (1): 112–118.

Chapter 1

Opportunities for Nuclear Energy
Internationally, concern over climate change continues to grow. With rising populationand economic output, only a concerted global effort to decarbonize current energy
production systems will have any meaningful impact on climate change. In this context,
we examine opportunities for nuclear energy technologies to play a larger and moreconsequential role in meeting U.S. and global energy needs in a carbon-constrained world.
First, we review the status of nuclear energy today and the outlook for the industry overthe next couple of decades. We then develop projections to 2050 for optimal electricalgeneration system capacities in the United States and internationally under a variety of
low-carbon scenarios. We consider whether equipment supply chain barriers could impede
the industry’s growth opportunities over this timeframe and assess nuclear energy’s
potential to play an expanded role in industrial applications beyond electricity supply.

1.1 CURRENT STATUS AND OUTLOOKFOR NUCLEAR ENERGYElectrical energy production is a major componentof the energy industry in the United States: about
40% of primary energy consumption goes to
producing electricity and the fraction is similar
worldwide (Figures 1.1a and 1.1b) (Lawrence
Livermore National Laboratory 2014). Electricity isa versatile form of energy and useful in all aspectsof daily life, including for residential, commercial,industrial, and transportation applications. The
electrical energy sector is also projected to grow
(U.S. Energy Information Administration 2017a)
given electricity’s flexibility as an intermediate
form of useful energy (an example would be theelectrification of the transportation sector formass transit and for individual transportation).

International Outlook forElectricity Production
The electrical energy sector is one of the more
dynamic growth areas among all energy markets
internationally and electricity is the world’s
1

fastest-growing form of energy, as it has been
for many decades. The U.S. Energy Information
Administration’s International Energy Outlook(IEO) estimates that net electricity generationworldwide will grow almost 45% by mid-century,
from 23.4 trillion kilowatt hours (kWh) in 2015 to25.3 trillion kWh in 2020 and 34.0 trillion kWh
in 2040 (U.S. Energy Information Administration
2017b). The strongest growth is projected tooccur among developing, non-OECD1 nations: led
by China and India, the growth rate for electricalenergy generation in non-OECD countries is
projected to average 1.9% per year from 2015 to
2040. In the OECD nations, where infrastructures
are mature and population growth is relatively
slow or declining, electric power generation is
projected to increase by an average of 1% peryear from 2015 to 2040 (according to the IEO
Reference case). In the United States, electricity
demand is projected to grow between 0.5% and
1% per year over the same time period—less thanthe OECD average.

 he Organisation for Economic Co-operation and Development is an intergovernmental economic organizationTwith 35 member countries. It was founded in 1960 to stimulate economic progress and world trade (OECD 2017).

Chapter 1: Opportunities for Nuclear Energy

1Figure 1.1a: 2011 world energy flow

(Lawrence Livermore National Laboratory 2014) (1 Petajoule = 1×1015 Joules ≈ 0.001 Quadrillion BTU)
Source: LLNL 2014. Data is based on IEA’s Extended World Energy Balances (2013 Edition). All quantities are rounded
to 2 significant digits and annual flows of less than 0.05 PJ are not included. Totals may not equal sum of flows
due to statistical differences. Imports and Exports represent gross global trade. Further detail on how all flows arecalculated can be found at flowcharts.llnl.gov. LLNL-MI-410527.

Long-term global prospects continue to improvefor electricity generation from renewable energy
sources (including hydropower) and natural gas(Figure 1.2). Worldwide, renewable generation
is projected to increase at a rate of 2.8% peryear from 2015 to 2040. Natural gas is the next
fastest-growing source of electricity generation
with a projected average annual growth rate of
2.1% worldwide. Nuclear energy, by contrast, isprojected to grow more slowly, at a rate of 1.5%
per year worldwide. In China alone, electricity
demand is projected to increase at a rate of 1.7%
per year over the same 2015–2040 period, while
generation from renewables is projected to growby 3.5% per year and generation from natural
gas and nuclear (together) by more than 6.5%
per year.

2

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Many countries have enacted environmental
policies and regulations that are intended to curtail
greenhouse gas emissions from the power sector
by reducing the use of fossil fuels. These efforts
have continued to reduce the relative importanceof coal as a dominant fuel source for electricity
generation. By 2040, electricity generation fromnatural gas and renewable energy sources is
estimated to surpass electricity generation fromcoal on a worldwide basis. These projections
do not include the implications of actions that
could be taken to reduce carbon dioxide (CO2)emissions under the Paris Agreement, nor do they
include the effects of the Clean Power Plan in the
United States since that policy has been targeted
for repeal and is subject to legal challenges.

Figure 1.1b: 2016 U.S. energy flow

(Lawrence Livermore National Laboratory 2017) (Quad = Quadrillion BTU = 1×1015 BTU ≈ 1,000 Petajoules)
Source: LLNL March, 2017. Data is based on DOE/EIA MER (2016). This chart was revised in 2017 to reflect changes
made in mid-2016 to the Energy Information Administration’s analysis methodology and reporting. The efficiency ofelectricity production is calculated as the total retail electricity delivered divided by the primary energy input into
electricity generation. End U.S. efficiency is estimated as 65% for the residential sector, 65% for the commercial
sector, 21% for the transportation sector, and 49% for the industrial sector, which was updated in 2017 to reflect
DOE’s analysis of manufacturing. Totals may not equal sum of components due to independent rounding.
LLNL-MI-410527.

Figure 1.2: Current and projected world net electricity
generation by energy source, 2010–2040 (trillion
kilowatt hours)
World Net Electricity Generation and
Projections by Source
40(Trillion kWhr)

35
30

Nuclear25

Renewables

20

Natural Gas

15
10

Coal

5
0

Liquids
2010 2015 2020 2025 2030 2035 2040

(U.S. Energy Information Administration 2017b)
Note: Renewables include hydroelectric power

International Status and Outlook
for Nuclear Energy
Today, the world produces as much electricity from
nuclear energy as it did from all sources combinedin the early 1960s. Civilian nuclear power plants
supply 11% of global electricity needs, withreactors in 32 countries. The installed electricalgenerating capacity of commercial nuclear
power reactors worldwide totals more than
392 gigawatts (GWe). At present, 55 nuclear powerreactors are under construction, equivalent to 16%
of existing nuclear capacity (International Atomic
Energy Agency 2018). However, in a few countries(e.g., Slovakia, Ukraine) plant construction has
been delayed for many years, while in the UnitedStates, plans to build two new reactor units at the
V.C. Summer Nuclear Generating Station in South
Carolina were canceled in 2017.

Chapter 1: Opportunities for Nuclear Energy

3Electricity generation from nuclear energy
worldwide is projected to increase from 2.3 trillion
kWh in 2012 to 2.7 trillion kWh in 2020 and
3.7 trillion kWh in 2040 based on estimates in
the IEO Reference case. Concerns about energy
security and CO2 emissions are influencing thedevelopment of new nuclear generating capacity.
Virtually all the projected net expansion inworldwide installed nuclear capacity occurs in
non-OECD countries, led by planned additions of
nuclear capacity in China and India specificallyover the 2012–2040 timeframe. Other non-OECD
countries that are interested in nuclear energy
have smaller but still noteworthy plans to develop
new nuclear capacity. For example, the United
Arab Emirates has embarked on a nuclear
power program in close consultation with theInternational Atomic Energy Agency (IAEA).
Led by a Korean electric power consortium,
four Korean-designed nuclear power reactors(with combined capacity of 5.6 GWe) are underconstruction at the United Arab Emirates’ Barakahsite for 2020. The first unit is complete andexpected to go online in 2018.
In the OECD portion of Europe, overall nuclear
capacity is expected to decline by more than 30%.
In Japan, nuclear generation is likewise expected
to fall (in the IEO Reference case, Japan’s nuclear
capacity in 2040 remains far below the level it wasprior to the Fukushima accident). As a result, thecombined capacity of all nuclear power plants inOECD countries is projected to decrease by 6 GWefrom 2012 to 2040 (World Nuclear Association
2017). This estimate does not include recently
announced plant closures in the United States(as noted previously, these closures are beingcaused by the inability of plant owners to recoverproduction costs in a deregulated market andmake the additional capital investments needed
to extend plant operating life).

Decarbonizing the Electrical Energy Sector
Deep decarbonization of the electrical energy
sector globally, where “deep decarbonization”
means a substantial reduction (one order ofmagnitude or more) in greenhouse gas emissions,is needed to mitigate the effects of climate change
in this century. Achieving deep decarbonization

4

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDrequires a technical pathway to reduce CO2
emissions. A number of studies have noted thatdifferent mitigation pathways are possible withdifferent likelihoods of achieving an emissions
reduction goal that meets or exceeds the
widely accepted 2050 target of limiting global
average warming to 2°C (International Energy
Agency 2017) (Chen, et al. 2016). Political andcultural factors will influence the choice of any
particular decarbonization pathway in individual
countries. Currently, energy efficiency and energy
conservation measures are being employed
as a cost-effective way of reducing energy
demand and thereby reducing carbon emissions.
However, these measures will not be adequate
to markedly reduce global emissions. Studies
that have explored options for achieving deep
decarbonization by 2050 have primarily focusedon the potential to transform the electricity sector
because the costs of carbon reductions in this
sector are initially lower than for other majorenergy sectors. By contrast, significantly changing
and decarbonizing the transportation andindustrial sectors by mid-century is expected
to be more difficult and costly.
In this analysis, we considered a broad range
of decarbonization targets for the electricity
generation system. For example, in 2010, CO2
emissions from U.S. electricity generation
averaged about 500 grams per kilowatt hour
(gCO2/kWh). To do its part to reach the 2050
climate stabilization goal set by the Paris
Agreement, the United States would need toreduce CO2 emissions from electricity generation
by more than 97%—in other words, reduce thecarbon intensity of its electricity mix from
500 gCO2/kWh to less than 15 gCO2/kWh. Thistarget is based on analyses that have estimatedthe scale of emissions reductions needed in
the electric and non-electric sectors to limit
greenhouse gas concentrations in the atmosphereto 450 parts per million (ppm) CO2 equivalent(Sachs, et al. 2014).
To provide context for these emissions targets,
Table 1.1 presents information about CO2
emissions rates for electricity generation in
selected countries in 2017 (the same countries

Table 1.1: Current electricity sector CO2 emission ratesa compared to 2050 emissions goals
Country

2017 CO2 Emissions
from Electricity

2050 IEA Energy
Technology Perspectives
2°C Scenario

MIT Joint Program Outlookf

United States≈470 gCO2/kWhb

11 gCO2/kWhe≈1 gCO2eq/kWh

China≈680 gCO2/kWhc

24 gCO2/kWhe≈1 gCO2eq/kWh

United Kingdom ≈350 gCO2/kWhe

11 gCO2/kWh (for EU)≈1 gCO2eq/kWh≈90 gCO2/kWh

11 gCO2/kWh (for EU)≈1 gCO2eq/kWhdFrancedeNote that these emission rates are technically given in CO2-equivalent terms—that is, they include emissionsof non-CO2 greenhouse gases, such as methane, converted to a CO2-equivalent mass based on their relative
warming effects in the atmosphere. ​b (U.S. Energy Information Administration 2017a); c​ (Liu, Ma, and Kang 2017); ​d(Gogan, Partanen, and Denk 2017); ​e (International Energy Agency 2017); f​ (Chen, et al. 2016)aare included in the modeling analysis discussed
in Section 1.2). For comparison, we reference twoanalyses that estimate the CO2 reductions neededto achieve the 2°C climate stabilization goal by
2050 (in other words, deep decarbonization).
One analysis, by the International Energy Agency(IEA) estimates that emissions for the electricity
generation sector must be below 11–24 gCO2/kWh.
In a separate study, researchers at MIT estimatethat emissions need to be reduced to levels
approaching 1 gCO2/kWh. Another study findsthat to mitigate financial risk given uncertainty
about future climate policy, the best strategy
for the energy industry is to invest in a rangeof electricity generation sources, including asignificant fraction of non-carbon technologies(Morris, et al. 2018). Thus, our analysis considersa range of emission constraints from modest
carbon reductions to deep decarbonization. Thisapproach is consistent with past work (Sepulveda
2016), which has examined emission targets forthe year 2050 that range from 400 gCO2/kWh
to 1 gCO2/kWh.
Another consideration is whether the deploymentof low-carbon energy technologies like renewables
or nuclear can be accomplished in the timeframe
needed to substantially displace fossil fuels by
2050. Rapid deployment is critical to achieve
current international climate mitigation goals.
In many countries, solar and wind have achieved
notable levels of penetration in electricity
generation markets over the last decade, and thistrend is expected to continue based on current IEO
estimates. Our analysis indicates that, historically,large-scale increases in low-carbon generation
have occurred most rapidly in connection withadditions of nuclear power (Figure 1.3).
Recent work by Qvist and Brook (2015) examines
the potential for a large-scale expansion of nuclear
energy globally to replace fossil fuel electricity
production. Their analysis uses empirical datafrom the French and Swedish light water reactor
programs, when those countries aggressively
pursued nuclear power expansion as part of theirnational energy policies. The results indicatethat if many nations added nuclear capacity
at the same rate per capita that France andSweden achieved during their national expansion,coal- and gas-fired generation could be replaced
worldwide. In their projections, Qvist and Brook
consider potential constraints and uncertainties
that could affect future nuclear expansion, suchas differing relative economic output acrossregions, current and past unit construction timeand costs, electricity demand growth forecasts,
and the retirement of existing nuclear plants. Their
analysis concludes that the global share of fossil
fuel electricity could be replaced in 25–35 years.

1.2 THE ROLE OF NUCLEAR ENERGY
IN THE OPTIMAL ELECTRICITY
GENERATION SYSTEM IN 2050
The challenge for future electricity generation
systems worldwide is to avoid harming theenvironment while delivering high levels ofelectricity security, reliability, and affordability.
Carbon reduction objectives will be a key factor,

Chapter 1: Opportunities for Nuclear Energy

5Figure 1.3: Electricity growth (kWh per year per capita) based on actual data for added power capacity
in various countries
Nuclear Sweden 1974-1983

730

Nuclear France 1979-1988

627

Nuclear US 1981-1990

178

Natural Gas US 2001-2010

548

Coal China 2005-2014

339

Solar&Wind Spain 2003-2012

120

Solar&Wind Germany 2007 - 2016

98

Solar&Wind Denmark 2007 - 2016

92

0

100

200

300

400

500

600

700

800

Average added kWh per capita per year

Assumes 90% capacity factor for dispatchable energy sources (nuclear, natural gas, coal) and the following
capacity factors for wind/solar: Germany 19%/9%; Spain 25%/33%; Denmark 26%/7% (based on historical record
for best 10-year period).

with national and international energy and climate
policies providing guidance for future investment
decisions. While there is agreement about theneed to decarbonize the electric power sector to
mitigate climate change, considerable uncertainty
and debate remains about the relative contributionof various low-carbon technologies in future
power systems. The optimal technology mix ina carbon-constrained environment will dependon the characteristics of the individual energy
technologies employed.
While government policies and business models
will continue to evolve, our goal here is to examine
the role nuclear energy can play in a decarbonizedelectricity market in the 2050 timeframe. We
address two questions:

6

1.

What are the long-term prospects for nuclear
energy in a decarbonized electricity market
under different technological scenarios?

2.

What would the cost of nuclear technology
need to be for nuclear energy to have a role?

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Using only energy technology costs or levelized
cost of electricity (LCOE), a widely-used metricfor comparing electricity generation costs, fails toadequately value the production of dispatchable,
low-carbon power at the system level;
furthermore, these metrics have shortcomings
when it comes to evaluating system integration
costs. The overall value of a given technology tothe electricity system can only be understoodwhen technologies are assessed together, not in
isolation. Decision support tools, including powersystem optimization models, can help explore
these synergies; illuminate key mechanisms,
uncertainties, and risks; and guide power system
planners, policy makers, and businesses. In
particular, capacity expansion (or capacity
planning) modeling tools have historically beenused to explore what mix of available electricity
generation resources would produce least-cost
outcomes for the system as a whole under
different scenarios.

GenX Simulation Approach
To quantify the role of nuclear power, we use
GenX, a power system decision support tool
(Jenkins and Sepulveda 2017), to explore theoptimal electricity generation mix for minimizing
total system generation costs subject to a setof pre-specified scenarios. Each scenario ischaracterized by a CO2 emissions limit; a year-longhourly demand profile; region-specific, year-longhourly availability profiles for solar and windresources; and a set of investment and operationalcosts for different systems under different carbon
constraints. We consider two alternative pathwaysfor each scenario. In the first one, nuclear power
technology is allowed as an investment option in
the least-cost system portfolio; in other words,
nuclear is deployed only if it is economicallyefficient for the electricity generation system.
In the second pathway, nuclear power technology
is excluded as an investment option and cannot
be deployed. The difference in total systemgeneration costs between these two pathways
represents the value of nuclear power and istermed the ‘opportunity cost’ of nuclear energy.
We consider carbon emission targets of 100, 50,
10, and 1 gCO2/kWh in our system analysis,
as well as a ‘business-as-usual’ targetof 500 gCO2/kWh.
Our analysis includes a wide range of assumptions
about cost and technology to investigate thebreadth of conditions under which nuclear energy
can play a significant role. The different technology
scenarios, wherein input parameters for individual
technologies vary from an assumed ‘nominal case’scenario, can be used to assess the sensitivity of
our results to changes in these assumptions.
GenX optimizes the electricity generation capacity
mix by minimizing the objective function of total
annualized system generation cost for a given
scenario. Its results account for capital cost andfinancing charges, fixed operating costs, andvariable operating costs, including fuel charges.
The optimization for each scenario is subject
to several constraints: (a) the need to match
hourly electricity dispatch to electricity demand;(b) technology-specific operating constraints, suchas allowable ramp rates and unit commitments
for dispatchable generators; and (c) CO2 emission
limits (expressed in gCO2/kWh).

GenX is configured to consider a full year ofoperating decisions, in hourly intervals, torepresent a future planning year. In this sense,
the model is static because its objective is not todetermine when investments should take placeover time to reach a given end state, but rather
to produce a snapshot of the minimum-cost
technology mix for the electricity system undera set of pre-specified conditions for some year
in the future (in this case, 2050).
We express our results in terms of (a) the average
cost of generation in dollars per megawatt hour($/MWh), where this cost figure represents total
system cost over total demand served by thesystem throughout the year; and (b) electricity
generation capacity required to meet the load.
For our analysis, we characterized different
systems in the United States, Europe, and China
using region-specific data on chronologicalhourly demand and hourly capacity factors forrenewable generators.
To make the simulation computationally tractablein all our scenarios, transmission networks
were simplified to a single node representation(i.e., there are no transmission bottlenecks orlosses; this is sometimes referred to as the ‘copper
plate assumption’), assuming no transmission
constraints exist given future network
reinforcements. We further assume that electricity
flows are unimpeded within regions and electricity
generated in a region serves only electricity
demand in that same region. In other words, ourscenarios do not allow for out-of-region imports
or exports of electricity. Table 1.2 summarizes
required inputs and simulation outputs using the
GenX modeling tool. Electricity transmission costs
are also not considered. Details are provided inAppendix A.
Due to computational time constraints, welimited the number of technology options foreach optimization scenario. A large light water
reactor (1,000 MWe) is used as the surrogate
for advanced nuclear technologies since theestimated capital, fuel and operating costsof these technologies are considered to be

Chapter 1: Opportunities for Nuclear Energy

7Table 1.2: Inputs and outputs of the GenX model
Inputs

Outputs• Solar PV hourly capacity factor• Optimal installed electricity generation capacity mix• Wind hourly capacity factor• Total system cost

• Hourly historical demand and demand growth• Hourly operation of each resource technology• Fixed (capital and O&M) and variable (O&M,
cycling, etc.) costs for each resource technology• System carbon emissions• Operational parameters for each technology• Energy contribution and capacity factor for eachtechnology• Fuel parameters such as emissions rate and costcomparable to current light water reactor systems,
as will be discussed in Chapter 3. Table 1.3 shows
technology options for both pathways (withand without nuclear energy as an option in thecapacity mix).
We used GenX to model the optimal electricity
system mix in selected regions of the worldin 2050. This global perspective is importantsince the cost of different electricity generation
technologies varies regionally as do the availabilityof renewable resources and expected electricity
demand patterns. All of these elements shape theleast-cost electricity generation mix. We modeled
electricity systems for a total of six regions in
China, Europe, and the United States:• Tianjin, Beijing, and Tangshan (T-B-T), China

France, and the United Kingdom), technology
costs—except costs for storage—were scaled
from U.S. costs based on scaling factors calculated
by comparing U.S. data to costs reported by theInternational Energy Agency (2015). Overnight
costs are shown in Table 1.5. Cost assumptions are
discussed in detail in Appendix A.

GenX Simulation Results
Figure 1.4a presents the results of our analysis for
Texas, showing the total system cost of electricity
generation for five technology scenarios:
1.

A No Nuclear case where nuclear is not anallowed option.

2.

A Nuclear—Nominal Cost case in which nuclear
technology can be selected at the currently
projected ‘nth-of-a-kind’ (NOAK) overnight
cost of $5,500/kWe in 2050 (National
Renewable Energy Laboratory, 2016).

3.

A Nuclear—Low Cost case in which nuclear
technology can be selected at a cost that is
25% lower than currently projected for 2050.
This estimate is based on our analysis ofopportunities to reduce the overnight cost of
nuclear by employing innovations in enabling
technologies (see Chapter 2).

4.

A Nuclear—Extremely Low Cost case in which
nuclear technology can be selected at a costthat is 50% that of the currently projected
cost for 2050. This is a long-term cost goalfor many advanced reactor technologies (U.S.
Department of Energy 2016).

• Zhejiang, China• France, Europe• United Kingdom, Europe• Texas, United States• New England, United States
The data sources used as inputs for eachelectricity system are summarized in Table 1.4.
Operating parameters (e.g., efficiencies) for eachtechnology option were assumed to be constantacross all the electricity systems modeled andare given in Appendix A. Estimated technology
costs for the United States in 2050 were takenfrom National Renewable Energy Laboratory(2016); battery storage costs were taken from
Lazard (2015). For all other regions (i.e., China,

8

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Table 1.3: Technology options for each pathway
Nuclear Energy IS An Allowed Option

Nuclear Energy Is NOT An Allowed Option

Carbon-Free Options

Carbon-Free Options• Photovoltaic (PV) Solar• PV Solar• On-shore Wind

• On-shore Wind

• Light-water Reactor (LWR) Nuclear• Coal with CCS (IGCC-CCS)• Coal with Carbon Capture and Storage (CCS)• Natural Gas with CCS• Natural Gas with CCS

Carbon Options

Carbon Options• OCGT• Open Cycle Gas Turbine (OCGT)• CCGT• Combined Cycle Gas Turbine (CCGT)• Coal (IGCC)• Coal (IGCC)

Storage Options

Storage Options• Battery Storage• Battery Storage• Hydro-electric Storage (Fixed)• Hydro-electric Storage (Fixed)

Table 1.4: Data sources for GenX scenarios

Solar Hourly
Capacity Factor(2016)
Wind Hourly
Capacity Factor(2016)
Historical Hourly
Elec. DemandabFranceUnited Kingdom

Texas, UnitedStatesNew England,
United States

Renewables
NinjaaSepulveda 2016

Sheffield Solard

Sepulveda 2016

Sepulveda 2016

Renewables
NinjaaRenewables
NinjaaSepulveda 2016

EnAppSyse

Sepulveda 2016

Sepulveda 2016

CEICb and
SWITCHc

CEICb and He
et al.c

Sepulveda 2016

Gridwatchf

Sepulveda 2016

Sepulveda 2016

Tianjin, China

Zhejiang, China

Renewables
Ninjaa(Pfenninger and Staffell 2016) (Staffell and Pfenninger 2016) (Pfenninger and Staffell, Renewables.ninja) ​(CEIC 2017); ​c (He, et al. 2016); d​ (The University of Sheffield 2017); e​ (EnAppSys 2017); f​ (Gridwatch 2017)

Table 1.5: Overnight cost inputs

UnitedStates

China
UnitedKingdom
FranceCost($/kW)
Low
NominalHigh
Low
NominalHigh
Low Cost
NominalHigh
Low
Nominal
High

Coal
IGCC

OCGT

CCGT

805

948

3,515

421

496

865

890

Nuclear

Wind

4,100

1,369

1,160

5,500
6,900
2,094
2,796

953

3,515

6,070
8,142

980

3,515

1,553
1,714
1,117
1,267
1,398
1,887
2,142
2,363
1,511
1,715
1,892

5,067
6,797
8,496

Coal
IGCC+CCSGas
CCGT+CCS

551

Battery
Storage
429

917
1,898
404
671
1,389
484
804
1,665
481
801
1,657

715
1,430
429
715
1,430
429
715
1,430
429
715
1,430

5,876

1,720
2,215

1,940

900
1,159

5,875

1,434
1,847

5,876

1,475
1,899

Solar

Assumed LCOEs for different technologies, based on nominal U.S. costs, were as follows: wind – $72/MWh; solar –$99/MWh; nuclear – $97/MWh; CCGT-CCS – $90/MWh; OCGT – $87/MWh; CCGT – $64/MWh; IGCC – $77/
MWh; IGCC-CCS – $125/MWh. Note that these LCOEs assume U.S. Energy Information Administration capacity
factors of 34% for wind and 25% for solar.

Chapter 1: Opportunities for Nuclear Energy

95.

Nuclear—High Cost case where the nuclear
cost is 25% higher than the currently projected
cost for 2050 based on current first-of-a-kind(FOAK) costs.

Texas has high renewable potential (windy
and sunny climate) and low natural gas costs.
This suggests a region where nuclear may not
be competitive or play a large role. Consistent
with this prediction, nuclear is not part of theleast-cost generation mix for Texas in 2050
in the ‘business as usual’ case where carbon
emissions are unconstrained and the average
emissions rate remains at the 500 gCO2/kWhcurrent world average. Even in Texas, however,nuclear capacity (at a nominal overnight cost of$5,500/kWe) is part of the least-cost generation
mix in cases where CO2 emissions are limited toless than 50 gCO2/kWh. This is due to the valuethat nuclear energy offers to the system as a
low-carbon generation option. If the capital costsof nuclear generation are reduced to the extent
discussed in Chapter 2, nuclear energy becomes
more competitive and begins to contribute to thesystem mix at a less stringent emissions limit of
100 gCO2/kWh. This result shows that capital
cost has a major influence on nuclear energy’s
ability to be part of the least-cost electrical systemgeneration mix.
Figure 1.4b shows installed capacity by generation
technology for the optimal (least-cost) generation
mix under different nuclear cost scenarios anda discrete set of emission constraints between
100 and 1 gCO2/kWh. We also include a ‘businessas usual’ case (at 500 gCO2/kWh) to show thecalculated optimal electrical system mix in 2050
with current CO2 emissions.
As can be seen in Figures 1.4a and 1.4b, whichshow system cost and system capacities,
respectively, imposing a carbon limit reduces the
deployment and use of fossil fueled generation.
The figure shows this impact for Texas, but theresult is generalizable to any power system.
The effect of a carbon constraint on fossil fuelgeneration, at the specific level of that constraint,
depends on the availability and cost of renewable
resources. Reductions in fossil fuel capacity have10

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDa direct impact on the value of renewables, evenwhen renewables are paired with energy storage,
due to the lack of backup capacity during periodsof rapid change in renewable output and theneed to move greater amounts of energy fromhours with higher renewable output to hours withlower renewable output. This increases system
requirements for battery storage and for added
renewable generation to act as backup capacity—and results in higher system costs.
Figure 1.4a shows that excluding the deploymentof a firm low-carbon generation resource, likenuclear, noticeably increases system costs
because it necessitates the deployment of lessefficient forms of generation and energy storage
to back up intermittent renewables. This effectis most pronounced at carbon emission targets
below 50 gCO2/kWh (i.e., at 10 gCO2/kWhand 1 gCO2/kWh). Figure 1.4b also shows that
reductions in nuclear capital cost lead to nuclear
deployment not only in scenarios that featurenear-zero emissions limits but also in scenarioswith more modest emissions targets(100 gCO2/kWh and 50 gCO2/kWh).
The modeling results for installed capacity (Figure1.4b) point to a further explanation for the higher
system costs that result when nuclear is excluded
as an option in scenarios with carbon constraints.
With no nuclear contribution, large build-outs ofwind, solar, and battery storage are required tomeet a stringent CO2 constraint. This is evident
in the 10 gCO2/kWh scenario and even more soin the 1 gCO2/kWh scenario, where total installedcapacity in the no-nuclear case is two to threetimes total installed capacity in the nuclearnominal case. This significant increase in installedcapacity comes at a large investment cost, which
increases total system cost.
Another way to understand these results is to inferthe ‘marginal cost of carbon’ by looking at changes
in system cost in relation to changes in the CO2target. At progressively lower levels of allowable
CO2 emissions, one could expect average electric
system costs to increase, since lower cost, fossil
fuel generation technologies (coal or natural gas)
are being replaced by higher-cost, low-carbon

Figure 1.4a: Texas cost of electricity generation
Average Generation Cost ($/MWh)

180
160
140
120

Nuclear - None100

Nuclear - High Cost

80

Nuclear - Nominal Cost

60

Nuclear - Low Cost

40

Nuclear - Extremely Low Cost

20
0

500

100

50

10

1

Emissions (g/kWh)

The error bars in the figure represent numerical uncertainty in the calculations.
Figure 1.4b: Optimal capacity mixes for Texas
Nuclear - None

Nuclear - High Cost

100%

Nuclear - Nominal
Cost

Nuclear - Low Cost

Nuclear - Extremely
Low Cost

80%

500
400

60%

300
40%
200
20%

Total Installed Capacity (GW)

Total Installed Capacity (MW)

600

100
0

g/

50

0
10

50

0

g/
kW

h,

g/
kW 121h, GW
k 17
10 Wh 4 G
g/ , 1 W
kW 71
G
h
1
g/ , 25 W
kW 1
h, GW
55
6
10
GW
0
g/
kW
50
h
g/ , 17k
10 Wh 5 G
g/ , 1 W
kW 73
G
h
1
g/ , 24 W
kW 6
h, GW
18
9
50
GW
0
g/
10 kW
h,
0
g/
k 12
50 Wh 1 G
g/ , 1 W
7k
10 Wh 6 G
g/ , 1 W
kW 70
G
h
1
g/ , 18 W
kW 3
h, GW
16
3
50
GW
0
g/
10 kW
h,
0
g/
k 12
50 Wh 1 G
g/ , 1 W
3k
10 Wh 7 G
g/ , 1 W
kW 33
G
h
1
g/ , 13 W
kW 0
h, GW
14
8
10
GW
0
g/
kW
50
h,
g/
k 10
10 Wh 5 G
g/ , 1 W
kW 05
G
h
1
g/ , 10 W
kW 9
h, GW
11
6
GW

0%

Emissions (g/kWh)Natural Gas (OCGT and CCGT)

Coal (IGCC)

NuclearRenewables (Wind and Solar)

Storage (Pumped Hydro and Battery)CCS (CCGT and IGCC) Technologies

Total Installed Capacity (GW)(The left axis shows % of aggregate installed capacity; the right axis shows total installed capacity.)

Chapter 1: Opportunities for Nuclear Energy

11technologies (renewables, nuclear, or natural gas
with carbon capture and storage). The marginal
cost of carbon is an equivalent way to characterize
the effect of performance-based carbon emissions
targets. Table 1.6 shows the estimated marginal
cost of carbon based on the ratio of difference inelectric system costs to difference in CO2 targets.
As one would suspect, the marginal cost of carbon
increases as the emissions target becomes
more restrictive. The relationship is non-linear
at less stringent emissions targets(i.e., 100–500 gCO2/kWh) so these values
are lower bounds.
In addition to the large investments required tobuild out renewables, low-carbon scenarios that
exclude the use of nuclear energy come at the costof sizable land usage. As an illustration, for the
1 gCO2/kWh target in the Nuclear—None case, theland requirements for solar and wind generation
total just under 4 million hectares (about 5.5% of
the land area of Texas). This represents the largest
build-out of renewable energy in any of the Texas
scenarios. Land usage would be proportionately
larger for a no-nuclear, deep-decarbonization
scenario in any of the other regions we analyzed,
since none of them are as favorable for renewablegeneration and hence have lower renewablecapacity factors.
We did not consider land requirements for CO2
disposal as a constraint in our analysis. However,
we did model a limited set of scenarios for the
Texas region in which natural gas (combined
cycle gas turbine) generation with carbon captureand storage (CCS) is not available. Results forthese scenarios indicate that the relative nuclear
share increases for all the deep decarbonization
emission targets. This is not unexpected asa proportionate increase in nuclear capacity
and renewables with battery storage would beneeded to meet load if natural gas with CCS were
not available.
In regions that have more modest renewable
resource availability (in the United States andinternationally) and face different costs forrenewable generation, we limited our nuclear
technology cases to Nuclear—Nominal Cost and12

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Nuclear—Low Cost based on estimates fromthe U.S. National Renewable Energy Laboratory
for the nominal case and our own estimatesof the potential for cost improvement in the
low-cost case. Figures 1.5a through 1.5e show how
including nuclear as an option affects optimal
system generation costs under different carbon
constraints for the regions included in our analysis.
Results for New England (Figure 1.5a) are similar
to those for Texas in terms of the cost impacts
of including nominal cost nuclear technology in
scenarios that feature a carbon constraint. As in
the Texas case, nominal cost nuclear is deployed
only at emission targets of 10 and 1 gCO2/kWh.
With reduced nuclear costs (as in the Nuclear—
Low Cost scenario), nuclear generation plays arole at even the less stringent targets of 50 and
100 gCO2/kWh.
Compared to Texas, the cost-reduction benefitsof nuclear are higher in New England because thisregion is less favorable for renewable resources.
As a result, there is less renewable generating
capacity available in New England when demandis high than there is in Texas when that state’s
demand is high. To generate enough electricity inperiods of higher demand, New England requiresa larger amount of installed renewable capacity
and storage. This build-out of installed capacity
requires large capital expenditures, which translate
to higher system costs. Given less favorable
renewable conditions, imposing a more stringent
CO2 constraint causes a steep increase in thecost of generation. As the emissions constraint
tightens to require increasing reductions below
the ‘business as usual’ rate of 500 gCO2/kWh,the cost of substituting the next kWh of carbonemitting electricity with low-carbon electricity
increases. At less stringent emissions targets,carbon-emitting generation is displaced byrenewables during periods of high renewablepotential (i.e., sunny and windy days). As the
carbon constraint tightens further, electricity
generation during high renewable potential times
is already low-carbon and the challenge becomes
displacing carbon-emitting generation during
periods of lower renewable potential. This requires
either a large build-out of renewable capacity

Table 1.6: Marginal cost of carbon ($/ton-CO2) in Texas for a range of CO2 emission targets
CO2 Emission
Target (gCO2/kWh)
500 to 100
100 to 50
50 to 1010 to 1

NuclearHigh Cost

No Nuclear
25
92
363
6,390

NuclearNominal Cost

25
84
374
3,087

NuclearLow Cost

25
81
292
1,907

NuclearVery Low Cost

20
76
128
1,000

20
28
88
557

Figure 1.5a: New England cost of electricity generation
Average Generation Cost ($/MWh)

250
200
150
Nuclear - None100

Nuclear - Nominal Cost
Nuclear - Low Cost

50
0

500

100

50

10

1

Emissions (g/kWh)Figure 1.5b: T-B-T cost of electricity generation
Average Generation Cost ($/MWh)

250
200
150
Nuclear - None100

Nuclear - Nominal Cost
Nuclear - Low Cost

50
0

500

100

50

10

1

Emissions (g/kWh)

Chapter 1: Opportunities for Nuclear Energy

13with storage to compensate for periods of lower
renewable generation potential or a low-carbon
generation technology that is also dispatchable(i.e., available on demand), such as nuclear. As
a result, displacing a unit of carbon-emittingenergy generation at stricter carbon constraints
becomes much more expensive when nuclear is
not an option. Figures 1.6–1.10 show how excluding
nuclear affects renewables build-out.

In France (Figure 1.5e), low-cost nuclear ispart of the optimal system generation mix at a
carbon emissions target of 100 gCO2/kWh. At
nominal cost, nuclear is part of the optimal mix
at an emissions target of 10 gCO2/kWh. Also,
as in the other regions modeled for this analysis,
system costs rise sharply as the carbon target
becomes more stringent in scenarios that exclude
nuclear technology.

In the two Chinese provinces considered, T-B-T
and Zhejiang (Figures 1.5b and c), the systemcost benefits of including nuclear technology as
an option under nominal conditions are seen overthe full range of emission targets modeled (thatis, from 100 gCO2/kWh to 1 gCO2/kWh). For
example, in the Nuclear—Nominal Cost case, theaverage system cost of generation without nuclear
as an option at a 10 gCO2/kWh emission target
is more than three times the cost when nuclear
is included. This is because nuclear technology
is comparatively less expensive in China. Thus, it
is selected to be part of the generation mix evenat the least restrictive CO2 constraint. Notably,
nuclear technology is selected even in periodsof high renewable potential because it is the lesscostly option. However, it should also be notedthat this result is highly dependent on the low costof nuclear in the China scenarios. The values used
to scale nuclear costs for China are taken fromavailable public information that is used in OECDestimates (as noted in Chapter 2). If the actual
cost of nuclear technology in China is higher, theopportunity cost of excluding nuclear will be lower
than our modeling results indicate.

Figure 1.6 shows the optimal capacity mix for New
England for each of the cases: Nuclear—None,
Nuclear—Nominal Cost, and Nuclear—Low
Cost. As noted previously, this region’s more
limited wind and solar resource potential meansthat large amounts of installed renewablecapacity and battery storage are needed to meetsystem generation needs during periods of highdemand. In addition, substantial battery storage
capacity must be supplied to compensate forweather variability.

In the United Kingdom (Figure 1.5d), the cost
implications of including nuclear as an option
are similar to those calculated for the UnitedStates, with the same steep increase in average
generation costs with increasing strictness ofcarbon emission constraints. Nuclear provides
notable cost benefits at emission targets of 10 and
1 gCO2/kWh. An emissions target of 10 gCO2/kWh
is consistent with the level of CO2 reduction
estimated to be needed by 2050 for the U.S. andU.K. electricity sectors to achieve international
climate stabilization goals, according to the IEA
analysis discussed previously (Table 1.1).

14

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Figures 1.7 and 1.8 show the optimal capacity
mix for China’s T-B-T and Zhejiang regions,
respectively, for each of the cases: Nuclear—None,
Nuclear—Nominal Cost, and Nuclear—Low Cost.
The capacity trends shown in these figures forrenewables and battery storage are qualitatively
similar to those of the Texas and New Englandregions of the United States but are evenmore pronounced.
Similarly, Figures 1.9 and 1.10 show the optimal
capacity mix for the United Kingdom and France
for each of the cases: Nuclear—None, Nuclear—
Nominal Cost, and Nuclear—Low Cost.
Comparing optimal capacity mixes(Figures 1.6–1.10) with system electricity costs(Figures 1.5a–e), we find that higher system costs
are always associated with greater amounts of
installed renewable capacity (both wind and solar)
combined with battery storage. At lower carbon
targets when nuclear technology is not allowed
as an option, electricity generation must comefrom renewables as the only other completely
low-carbon option. Due to the intermittent natureof wind and solar generation, large amounts of
installed renewable and battery storage capacity

Figure 1.5c: Zhejiang cost of electricity generation
Average Generation Cost ($/MWh)

400
350
300
250
200

Nuclear - None

150

Nuclear - Nominal Cost

100

Nuclear - Low Cost

50
0

500

100

50

10

1

Emissions (g/kWh)Figure 1.5d: United Kingdom cost of electricity generation
Average Generation Cost ($/MWh)

400
350
300
250
200

Nuclear - None

150

Nuclear - Nominal Cost

100

Nuclear - Low Cost

50
0

500

100

50

10

1

Emissions (g/kWh)Figure 1.5e: France cost of electricity generation

Figures 1.5a-1.5e: The error bars in the figure represent numerical uncertainty in the calculations.

Chapter 1: Opportunities for Nuclear Energy

15

Figure 1.6: Optimal capacity mixes for New England
100%

Nuclear - None

Nuclear - Low Cost

Nuclear - Nominal Cost

80%

250
200

60%

150
40%
100
20%

Total Installed Capacity (GW)

Total Installed Capacity (MW)

300

50

0%

0

Emissions (g/kWh)Natural Gas (OCGT and CCGT)

Coal (IGCC)

NuclearRenewables (Wind and Solar)

Storage (Pumped Hydro and Battery)CCS (CCGT and IGCC) Technologies

Total Installed Capacity (GW)

Figure 1.7: Optimal capacity mixes for T-B-T
100%

Nuclear - None

Nuclear - Low Cost

Nuclear - Nominal Cost

900

700
600

60%

500
400

40%

300
200

20%

100
0

0%

Emissions (g/kWh)Natural Gas (OCGT and CCGT)

Coal (IGCC)

NuclearRenewables (Wind and Solar)

Storage (Pumped Hydro and Battery)CCS (CCGT and IGCC) Technologies

Total Installed Capacity (GW)16

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Total Installed Capacity (GW)

Total Installed Capacity (MW)

800
80%

Figure 1.8: Optimal capacity mixes for Zhejiang
Nuclear - None

Nuclear - Low Cost

Nuclear - Nominal Cost

1,600
1,400

80%

1,200
1,000

60%

800
40%

600
400

20%

Total Installed Capacity (GW)

Total Installed Capacity (MW)

100%

200
0%

0

Emissions (g/kWh)Natural Gas (OCGT and CCGT)

Coal (IGCC)

NuclearRenewables (Wind and Solar)

Storage (Pumped Hydro and Battery)CCS (CCGT and IGCC) Technologies

Total Installed Capacity (GW)

Figure 1.9: Optimal capacity mixes for the United Kingdom
100%

Nuclear - None

Nuclear - Low Cost

Nuclear - Nominal Cost

600

80%
400
60%

300

40%

200

20%

100

0%

0

Total Installed Capacity (GW)

Total Installed Capacity (MW)500

Emissions (g/kWh)Natural Gas (OCGT and CCGT)

Coal (IGCC)

NuclearRenewables (Wind and Solar)

Storage (Pumped Hydro and Battery)CCS (CCGT and IGCC) Technologies

Total Installed Capacity (GW)

Chapter 1: Opportunities for Nuclear Energy

17Figure 1.10: Optimal capacity mixes for France
Nuclear - None

Nuclear - Low Cost

Nuclear - Nominal Cost

800
700

80%

600
500

60%

400
40%

300
200

20%

Total Installed Capacity (GW)

Total Installed Capacity (MW)

100%

100
0%

0

Emissions (g/kWh)Natural Gas (OCGT and CCGT)

Coal (IGCC)

NuclearRenewables (Wind and Solar)

Storage (Pumped Hydro and Battery)CCS (CCGT and IGCC) Technologies

Total Installed Capacity (GW)

are needed to ensure that the system is always
able to meet demand. The large investments
needed to install this additional capacity increase
total system cost. This represents an opportunity
for nuclear technology, as the installed capacity
needed to meet demand using nuclear generation
is much less than the build-out required

18

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

for renewables. Because nuclear plants aredispatchable (they can operate when needed andare not dependent on an intermittent fuel source),
their average operating capacity factors aresubstantially higher than the operating capacity
factors for solar and wind generators without
battery storage capacity.

Table 1.7 shows the cost of excluding nuclear
technology as an option in the optimal capacity
portfolio mix for each of the six regions. This
cost is termed the ‘opportunity cost’ of foregoing
nuclear energy as a low-carbon option.2

Absolute Opportunity Cost(

We measure opportunity cost in two ways: asan absolute increase in generation cost and asa percentage increase in generation cost. Bothapproaches are defined below.

)(

)

)(

)

Average cost of electricity
Average cost of electricity
Opportunity Cost = generation without nuclear – generation with nuclear
technologies available
technologies available
Percentage Opportunity Cost(

Average cost of electricity
Average cost of electricity% Opportunity Cost = generation without nuclear – generation with nuclear
technologies available
technologies available% Opportunity Cost =Average cost of electricity
generation with nuclear
technologies available()

Table 1.7: Opportunity cost of excluding nuclear in the optimal installed capacity mix a
RegionTexas

New England

T-B-T

Zhejiang
UnitedKingdom
FranceNuclear
Costs

Carbon Emissions
500 gCO2/kWh

100 gCO2/kWh

50 gCO2/kWh

10 gCO2/kWh

1 gCO2/kWh

Nominal ~0% b

~0% b

~0% b

~0% b

$43.89/MWh (36.9%)

Low

~0% b

~0% b

~0% b

$12.02/MWh (12.9%)$60.53/MWh (59.1%)

Nominal ~0% b

~0% b

~0% b

$17.93/MWh (16.3%)$91.73/MWh (75%)

b$6.89/MWh (7.8%)$5.67/MWh (6.1%)$31.64/MWh (32.8%)$110.37/MWh (106.4%)

Nominal $8.38/MWh (14.5%)$21.46/MWh (37%)$42.48/MWh (73.9%)$84.87/MWh (148.7%)$162.41/MWh (273.9%)

Low

Low

~0%

$26.55/MWh (50.2%)$47.19/MWh (89.4%)$89.03/MWh (168.3%) $166.97/MWh (305%)

Nominal $10.91/MWh (19.2%)$12.73/MWh (23.8%)$22.91/MWh (40%)$59.51/MWh (103.3%)$176.58/MWh (299.2%) $296.46/MWh (497.2%)

Low$27.49/MWh (52.1%)$64.15/MWh (121.1%)$182.97/MWh (347.6%)$300.66/MWh(542.5%)

~0% b

~0% b

$23.79/MWh (14%)$175.34/MWh (97.6%)$14.39/MWh (26.9%)

Nominal ~0% b$11.53/MWh (8.4%)$51.83/MWh (36.5%)$202.79/MWh (133.2%)

Nominal ~0% b

~0% b

~0% b

$20.35/MWh (15.5%)$125.91/MWh (84.7%)

Low$15.97/MWh (14.8%)$21.13/MWh (19.6%)$38.69/MWh (34.2%)$153.27/MWh (126.4%)

Low

~0%

b

~0% b

~0%

b

 he absolute opportunity cost is shown in $/MWh and the percentage opportunity cost is shown in % inT
the parentheses.
b
These results are within the error band, and so are insignificant.
a2 he opportunity cost of nuclear is defined as the difference in price between a scenario that excludes nuclear
T
technology and a scenario that includes nuclear technology, with all other variables held constant.

Chapter 1: Opportunities for Nuclear Energy

19

As part of this analysis, we also examined thesensitivity of the GenX results to changes in
the cost and technology parameters that wereused for each region. The sensitivity study
was performed using costs from the National
Renewable Energy Laboratory (2016) and included
the following cases:• Low Renewables/Storage Cost
(60% of nominal costs)• High Renewables/Storage Cost
(200% of nominal costs)3• High CCS Cost (130% of nominal cost)• Low Natural Gas Cost (75% of nominal cost)• High Natural Gas Cost (125% of nominal cost)• 99% Efficient CCS Systems(nominal efficiency used was 90%)
• Demand Side Resources Considered4• Extreme Weather Year for Renewable Potential5
The results of the sensitivity study for Texas
and T-B-T are shown in Figures 1.11a and 1.11b.
We use the definition of opportunity cost
discussed previously and shown in Table 1.7.
Only three sensitivity cases produce resultsthat deviate significantly from the base case(with nominal assumed costs and performancefor nuclear technology). In both the ‘High
Renewable/Storage Costs’ and the ‘Extreme
Weather’ sensitivity cases, the opportunity costof excluding nuclear technology is higher. In fact,
higher renewable/storage costs more than double
the opportunity cost of nuclear. Conversely, low
renewable/storage costs significantly decrease

the opportunity cost of excluding nuclear. This isbecause with low renewable/storage costs, thebuild-out of installed renewable capacity andassociated battery storage, though still significant
in magnitude, is less costly and is chosen overbuilding nuclear (at nominal cost) in the cost
optimization. This result again underlines theinfluence of energy technology capital costs
in determining what is the least-cost electricalsystem generation mix.
Very similar patterns are seen in the sensitivity
results for all the other regions, which arepresented in Appendix B. To illustrate this point,consider the sensitivity results for the T-B-T
region in China (Figure 1.11b). The opportunity
cost of excluding nuclear is notable even at
100 gCO2/kWh and increases at lower CO2
emissions targets. In both the ‘High Renewable/
Storage Costs’ and ‘Extreme Weather’ sensitivity
cases, the opportunity cost of excluding nuclear
technology is higher, while in the ‘Low Renewable/
Storage Costs’ case the opportunity cost is lower.
Appendix C presents two supporting analyses
to help validate our GenX results. First, wedeveloped a GenX optimization for a simplified
electrical generation system and compared it toan analytic solution. In addition, we performed abenchmarking exercise that compared cost andemissions results from GenX to results obtainedusing another electrical system capacity expansion
model, JuiceBox. This benchmarking exercise was
performed for two regions: Texas and T-B-T.
Yet another way to compare the different
modeling scenarios is to examine the quantity ofelectricity supplied by different generation options
under different cost, technology, and emissions

 his case assumes that the current cost of renewables and storage, as reported in the National Renewable Energy
T
Laboratory’s Annual Technology Baseline report (2016), remains unchanged in 2050—in other words, costs forthese technologies do not fall over the next 30 years.
4The term ‘demand side resources’ refers to the grid operator’s ability to shift demand when generation is low
and to the ability of electricity consumers to curb demand when prices are high. In this case we assume that thegrid operator can shift up to 5% of demand each hour, with a maximum shift of six hours without additional cost.
The amount that consumers will curb demand depends on how much they value the electricity. Further detailconcerning assumed inputs for the value of electricity can be found in Appendix A.
5
To model an extreme weather year we arbitrarily lowered the generation potential for both wind and solar to 10%
of its original value for the entire first week of July. This time of year was chosen to illustrate the effect of prolonged
cloudy and windless days.
3

20

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Nuclear Opportunity Cost ($/MWh)Figure 1.11a: Texas sensitivity study results$120.00
Base Case$100.00

High Renewable/Storage Costs$80.00Extreme Weather YearHigh CCS Costs$60.0099% Efficient CCS$40.00

Low Natural Gas Prices$20.00High Natural Gas Prices$-

Demand Side Resources
100

50

10

1

Emissions (g/kWh)

Low Renewable/Storage Costs

Nuclear Opportunity Cost ($/MWh)Figure 1.11b: T-B-T sensitivity study results$300.00
Base Case$250.00

High Renewable/Storage Costs$200.00

Extreme Weather YearHigh CCS Costs$150.00

99% Efficient CCS$100.00

Low Natural Gas Prices$50.00High Natural Gas Prices$-

Demand Side Resources
100

50

10

Emissions (g/kWh)constraints. Figures 1.12a and 1.12b show total
electricity generation (TWh) for each technology
for Texas and T-B-T, respectively, over the timespan of one year.6
In Texas, for the cases with either no nuclear
or high-cost nuclear, natural gas with CCS
and renewables are used to satisfy demand atmoderate CO2 emission targets. However, with adeep decarbonization constraint, more than 80%
of demand is met with renewables if nuclear is
excluded. Due to the intermittent characteristics
6

1

Low Renewable/Storage Costsof wind and solar generation, this requires alarge expansion of renewable and energy storage
capacity—in fact, the capacity additions required
substantially exceed expected load. For thecases with nominal or low-cost nuclear, nuclear
generation is selected to meet demand, evenat moderate emission targets in the low-costnuclear cases. This result can be visualized byexamining the dynamics of load and generation
over the course of a week. Appendix D shows theelectrical load curve in Texas that must be methour-by-hour over the course of a summer week.

I n Figure 1.12, the total electricity generation reported is essentially ‘double counted’ when an oversupply of
renewable electricity goes into battery storage and then is fed back to the grid at a later time. This explains theincrease in generation noted for scenarios with no nuclear at low carbon targets.

Chapter 1: Opportunities for Nuclear Energy

21

Figure 1.12a: Texas dispatchable electricity generation technologies
Nuclear - High
Cost

Nuclear - None100%

Nuclear Nominal Cost

Nuclear - Extremely
Low Cost

Nuclear - Low
Cost

600

500

400

60%

300
40%

Total Generation (TWh)Total Generation %

80%

200
20%

0%

100

500 100 50

10

1

100 5010

1

500 100 50

10

1

500 100 50

10

1

100 50Natural Gas (OCGT and CCGT)

Coal (IGCC)

Nu clear

Renewables (Wind and Solar)

Storage (Pumped Hydro and Battery)CCS (CCGT and IGCC) Technologies

10

1

0

Total Generation (TWh)Figure 1.12b: T-B-T dispatchable electricity generation technologies
Nuclear - Nominal Cost

Nuclear - None

100%

700

Nuclear - Low Cost

600

500

400

60%

300
40%
200
20%

0%

100

500

100

50

10

1

500

100

10

1

500

100

50

10

Natural Gas (OCGT and CCGT)

Coal (IGCC)

NuclearRenewables (Wind and Solar)

Storage (Pumped Hydro and Battery)CCS (CCGT and IGCC) Technologies

Total Generation (TWh)2250

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

10

Total Generation (TWh)Total Generation %80%

When nuclear generation is an option, it supplies
increasingly larger fractions of demand. Figure
1.12 and Appendix D show that generation from
CCS technology declines as the stringency of the
carbon limit increases. This is because CCS is not
100% efficient—as a result, it still emits some
CO2 and cannot satisfy all of the demand without
exceeding the carbon emission limit. Only nuclear
and renewables with storage have the ability tosupply zero-carbon generation while minimizing
capacity expansion needs and thereby cost.
In the T-B-T cases, if nuclear power generation
is not an allowed option, the optimal system
mix under a modest carbon constraint uses
either fossil fuel generation or renewables tosatisfy periods with high demand, even with low
renewable generation potential. The cases that
require a large expansion of renewable capacity
are evident from the installed capacity results
shown in Figure 1.7. If nuclear is an option, then it
will be chosen during high demand periods since
this minimizes system costs over the range ofemission targets.

Summary
Achieving the widely accepted international
goal of stabilizing global average warming at 2°C
by 2050 requires ‘deep decarbonization’ of theelectricity generation mix. Specifically, expert
analyses have concluded that average CO2
emissions rates for electricity generationworldwide must decline to a range of
10–25 gCO2/kWh (compared to the current
world average of approximately 500 gCO2/kWh).
For the United States, we focused on two regions,
Texas and New England, that represent a range of
weather conditions. In both these regions, nuclear
technology provides notable system advantages
in terms of the average cost of electricity and the
optimal generation mix when the allowable carbon
emissions rate is reduced to less than
50 gCO2/kWh. These advantages become
particularly pronounced in cases where the target

emissions rate is at and below 10 gCO2/kWh.
These advantages grow in cases where we
considered enabling technologies that could lower
the capital cost of nuclear technology from thenominal values discussed in Chapter 2. Conversely,
nuclear energy’s advantages decreased notably
in cases that assumed cost improvements forrenewables and battery storage far beyond thosealready projected for 2050. All other sensitivity
cases we considered had a small effect on the
optimal generation mix and cost advantages ofnuclear technology. These results also indicatethat meeting deep decarbonization goals without
nuclear as an option will require a very substantial
expansion of renewable and battery storage
capacities, leading to significant cost increases.
These results are quite consistent with thosefound in a recent study by the Electric Power
Research Institute (Bistline and James 2018)that considers the role of advanced nuclear
technologies in future U.S. energy markets. Similar
outcomes for cost and nuclear penetration are also
observed for the United Kingdom and France.
In contrast to our modeling results for the UnitedStates and Europe, the inclusion of nuclear as a
generating option for the eastern provinces ofChina (T-B-T and Zhejiang) produces substantial
cost advantages even at less restrictive emission
targets, such as 100 gCO2/kWh—well above the
25 gCO2/kWh emission rate needed for China tomeet its 2050 climate change mitigation goals.
This result is largely driven by the relative capitalcosts of available energy technologies. As with the
U.S. and European cases, the results for China aresensitive to assumptions about renewable energy
and storage costs compared to nuclear technology
costs but are not substantially affected by any of
the other sensitivity cases considered.
Our analysis provides a comprehensive picture of
the opportunities for nuclear energy. Its results
point to several policy-relevant findings.

Chapter 1: Opportunities for Nuclear Energy

23

Findings:

The cost of new nuclear plants is high, and this significantly constrains the growth of nuclear
power under scenarios that assume ‘business as usual’ and modest carbon emission constraints.
In those parts of the world where a carbon constraint is not a primary factor, fossil fuels, whether
coal or natural gas, are generally a lower cost alternative for electricity generation. Under a modest
carbon emission constraint, renewable generation usually offers a lower cost alternative.
As the world seeks deeper reductions in electricity sector carbon emissions, the cost ofincremental power from renewables increases dramatically. At the levels of ‘deep decarbonization’that have been widely discussed in international policy deliberations—for example, a 2050
emissions target for the electric sector that is well below 50 grams carbon dioxide per kilowatt
hour of electricity generation (gCO2/kWh)—including nuclear in the mix of capacity options helps
to minimize or constrain rising system costs, which makes attaining stringent emissions goals
more realistic (worldwide, electricity sector emissions currently average approximately
500 gCO2/kWh).
Lowering the cost of nuclear technology can help reduce the cost of meeting even more modest
decarbonization targets (such as a 100 gCO2/kWh emissions target).

1.3 THE NUCLEAR EQUIPMENT
SUPPLY CHAIN
A robust nuclear supply chain is critical to thesuccess of the nuclear industry. As can be seen inrecent nuclear plant construction projects in thesoutheastern United States, when key construction
and construction management capabilities
atrophy, they can cause delays. Such delays in turnlead to cost overruns and threaten the project’s
viability. These challenges are discussed inadditional detail in Chapter 2. The nuclear supply
chain has become increasingly consolidated andglobalized (World Nuclear Association 2014).
It must be able to support current projectionsof growth in the nuclear industry, as well as thefurther expansions potentially needed to achieve
deep decarbonization scenarios. We therefore
investigated capacity challenges along the nuclear
supply chain to identify any potential bottlenecks.
Figure 1.13: Nuclear supply chain components

24

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDFor this portion of the analysis we simplified
the nuclear supply chain into three components(Figure 1.13): manufacturing, construction,and operation. Manufacturing includes the
manufacture of all necessary equipment for thereactor (for example, pressure vessel, steam
generators, etc.) as well as the transportationof manufactured equipment to the reactor site.
Construction includes the labor necessary toconstruct the reactor (for example, welders,electricians, etc.). It also includes the construction
management needed to complete projects
in a timely manner and on budget. Since thiscomponent of the supply chain can affect the final
cost of the plant via labor costs and productivity,
construction management experience, andinteraction between various construction
trades, it is important to consider supply chain
challenges related to plant construction. Thereis potential to address some construction supply
chain challenges with increased use of factory
manufacturing. Finally, the operation component
includes the labor and equipment needed on an
ongoing basis to operate the reactor (for example,
certified operators, fuel enrichment, etc.).
Our analysis of the nuclear supply chain is
described in Appendix E; we highlight only a
few key conclusions here. A 2014 survey ofexisting nuclear component suppliers (including
consolidations) by the World Nuclear Association
found no capacity constraints in the nuclear
equipment supply chain that would be expected tohinder the industry’s current growth projections.
Similarly, considering the typical duration of the
training cycle for construction labor and power
plant operators, we anticipate that nuclear
capacity growth would not be limited by that partof the supply chain. Somewhat more challenging
is the development of an experienced cadre ofconstruction managers. This is an issue in all major
construction projects. With over 55 new nuclear
reactors under construction at 32 sites worldwide,
junior construction managers could be embedded
at many of these sites as a way to provide
on-the-job training. Having managers with real
nuclear construction experience lead this effort
could be an effective way to supply the next waveof nuclear construction, which is expected to startin the late 2020s and last until the late 2030s.
Nevertheless, human resource development
requires a deliberate and concerted effort by the
nuclear industry. An international collaborative
effort in support of such development could
start now.

1.4 NUCLEAR ENERGYOPPORTUNITIES BEYOND
ELECTRICITY
Current nuclear power reactors produce
usable energy in the form of heat at modest
temperatures (approximately 300°C); thisheat is then converted to electricity by the useof a steam turbine power cycle. In advanced
nuclear reactors (so-called Generation-IV
designs), the primary energy product is again
heat but the heat is delivered at potentially muchhigher temperatures (500°C–800°C). Thesehigher operating temperatures offer a potential
opportunity for nuclear high temperature reactor(HTR) technology to provide useful process heatin industrial applications (Figure 1.14).
The industrial sector is an important energy user
in the U.S. economy and elsewhere: in the UnitedStates, 25% of all useful energy produced is used
for industrial processes and 80% of that energy
is in the form of process heat. However, industrial
applications are diverse in terms of the formsof energy used (from petroleum to specialty
products), the size of their energy demands (from1 MW to hundreds of MW of thermal energy), andthe temperatures required (which can range from
200°C to 1,500°C). To determine the potential
applicability of nuclear-based process heat in
the current U.S. industrial sector, we considered
two major attributes: the size of the industrial
site, where size is measured in terms of thermal
output (denoted by the subscript ‘th’), and therequired process temperature. Each year the U.S.
Environmental Protection Agency (EPA) publishes
emissions information from every industrial site
in the United States that produces more than
25,000 metric tons of CO2-equivalent emissions
per year (equivalent to a 0.2 MWth natural gas
facility) (U.S. EPA 2017). This database was used
to identify sites that would be large enough to
support nuclear process heat and would havetemperature requirements that are compatible
with advanced reactors. The site analysis assumed
a standard nuclear reactor size of 300 MWth.
We also considered a smaller reactor size of 150
MWth as part of a sensitivity study. A detailed listof assumptions and a complete description of theanalysis are provided in Appendix F.
Using these data and information about the U.S.
market, we then used scaling factors to estimate
the number of reactors that could potentially be
used in industrial applications worldwide. (Thescaling factors were calculated by comparing
the size of the relevant U.S. market to the world
market. Alternatively, if a market comparison
was unavailable, we used a GDP comparison to
calculate the scaling factor.) The results of thisanalysis are presented in Table 1.7 and Figure 1.15.

Chapter 1: Opportunities for Nuclear Energy

25

Figure 1.14: Potential industrial process heat applications for advanced high-temperature nuclear reactors

Figure 1.15: Nuclear process heat potential
Electricity and Industrial Carbon-Based Primary Het Market
59.9 Quadrillion BTU
Industrial Primary Heat Market
30%

Electricity Primary Heat Market
70%

NonCogenera on
Facili es

91.7%

Petroleumand Natural
Gas Systems
16.3%

NonNuclear

8.3%

Refineries
17.2%

NonNuclear

Chemicals
10.9%

NonNuclear

85.0%

Materials
4.2%

NonNuclear

89.9%

Waste
29.4%

NonNuclear

100%

77.7%

85.24%

22.3%

15.0%

11.1%

14.76%

NuclearOpportuni es

NuclearOpportuni es

NuclearOpportuni es

NuclearOpportuni es

NuclearOpportuni es

Metals
5.8%

NonNuclear

Others 11.9%

NonNuclear

Pulp and
Paper
4.4%

NonNuclear

100%

70.6%

0.7%

29.4%

99.3%

NuclearOpportuni es

NuclearOpportuni es

NuclearOpportuni es

Cogenera on
Facili es

They indicate that nuclear process heat could
capture about 17% (134 GWth) of the 795 GWthindustrial heat market in the United States. Fora smaller nominal reactor size of 150 MWth,nuclear’s potential share of the industrial process
heat market increases to 19%. By comparison,current installed nuclear capacity in the U.S. power
sector is about 300 GWth.

26

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

The main reason for nuclear technology’s relatively
low potential to be used in industrial process
heat applications is industry’s current practice ofintegrating heat from fossil fuels into processes
that use the same fossil fuels as feedstocks.
A further issue is the low technical readiness ofalternative processes that do not require fossil
fuels as feedstock. In particular, refineries are verylarge energy consumers, but they supplement
their external energy sources by using internallyproduced fuel gas from their own refining
processes—the fuel gas is otherwise a waste
product of refining crude oil. Hydrogen is alsoneeded in the refinement of petroleum products.
But there is currently no economically competitive
industrial method that would be suitable fornuclear process heat integration in refineries,
though major research campaigns are underway.
If a carbon constraint were to be imposed on
industrial sector emissions, the use of internallyproduced fuel gas from refinery processes would
be highly discouraged. A carbon constraint
would also require the process heat industry to
re-engineer many existing processes to enable
greater integration of low-carbon energy sources.
The net effect would be a larger market for nuclear
energy than is shown in Table 1.8.
The results shown in Table 1.8 are from an analysis
of current and near-term industrial heat markets.
In the future, however, there could be new energy

markets to satisfy—potentially with nuclear
energy. The most obvious market that could see
major changes is energy for transportation, which
could take the form of additional grid-supplied
electricity for electric cars, electricity and/or
process heat to produce hydrogen for fuel cells, orprocess heat to produce biomass-based synthetic
fuels. We assessed the magnitude of these threepotential opportunities using information about
current U.S. transportation fuel use.
The results of this assessment are shown in
Table 1.9. They indicate that for all threetransportation-energy market opportunities weconsidered, the potential heat load could be quite
substantial, particularly relative to the current
installed nuclear capacity base in the UnitedStates (at 300 GWth). Thus, if nuclear energy
were able to capture a major portion of newtransportation energy markets, this would expand
its role very significantly.

Table 1.8: Nuclear process heat potential
300 MWth Reactor
U.S. Capacity(MWth Installed) (%)

Industry
Co-Generation Facilities

82,800 (61.7%)

150 MWth Reactor

Global Capacity(MWth Installed) (%)
340,800 (59.8%)

U.S. Capacity(MWth Installed) (%)
86,250 (57.5%)

Worldwide Capacity(MWth Installed) (%)
355,050 (55.7%)

Refineries

15,600 (10.4%)

76,800 (12.1%)

17,250 (11.5%)

84,750 (13.3%)

Chemicals

7,800 (5.2%)

36,600 (5.7%)

7,050 (4.7%)

34,200 (5.4%)

Minerals

2,100 (1.4%)

8,700 (1.4%)

2,100 (1.4%)

8,700 (1.4%)

Pulp and Paper

12,600 (8.4%)

51,900 (8.1%)

21,300 (14.2%)

87,750 (13.8%)

Other

13,200 (8.8%)

55,200 (8.7%)

16,050 (10.7%)

66,450 (10.4%)

Total

134,100 (100%)

570,000 (100%)

150,000 (100%)

636,900 (100%)

Table 1.9: Comparison of transportation energy and reactor requirements for the United States
RequiredElectricity Load

Category
Transport Electrification
HydrogenElectrolysisb
Thermochemicalb

Bio-based Synfuel ProductionabRequired Heat Load(corresponding # of 300 MWth reactors)

335 GWe956 GWtha (3,186)

574 GWe

1,630 GWtha (5,461)—

803 GWth (2,676)—

1,305 GWth (4,348)

At 35% thermal efficiency.
These two options are not cumulative.

Chapter 1: Opportunities for Nuclear Energy

27

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Chapter 1: Opportunities for Nuclear Energy

29

30

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDChapter 2

Nuclear Power Plant Costs
Nuclear energy would seem to be ideally placed to meet the challenge of dramaticallyreducing emissions of greenhouse gases while at the same time expanding accessto energy and opportunity for billions of people around the world. Already, nuclear
technology provides the largest share of the world’s carbon-free energy, and the nuclear
industry’s early history demonstrated the feasibility of quickly scaling up production.
However, prospects for the continued expansion of nuclear energy are decidedly dim inmany parts of the world. Why would a technology that holds such promise for abundant,
clean, and reliable energy not be thriving? The problem is cost.
Our findings in Chapter 1 suggest that the imposition of carbon constraints creates
opportunities for nuclear. The magnitude of those opportunities increases as the costof nuclear decreases. This chapter focuses on better understanding the costs of nuclear
power systems because these costs impact the overall opportunities for nuclear energy.
As a starting point, we survey the innovation cycle of a set of important industries, oldand new. Understanding deployment and commercialization paradigms in other industries
can help crystallize similarities and differences with nuclear energy as a first step toward
identifying the important inherent characteristics that create challenges for nuclear
technology from a cost and development perspective. We then examine the high cost ofrecent nuclear plant construction projects, the root causes of these high costs, and the
new technologies that hold potential for reducing the cost of all nuclear energy systems.

2.1 DEVELOPMENT,DEMONSTRATION, AND
DEPLOYMENT PARADIGMSIN OTHER INDUSTRIESTo better inform our understanding of costreduction opportunities in the nuclear energy
industry, we began by surveying development
and deployment paradigms for new products
across a diverse set of technologies and industries,
including chemical plants, coal plants, offshore oiland gas production, jet engines, pharmaceuticals,
automobiles, satellites, and robotics. Througha series of interviews, summarized in Appendix
G, we sought to assess whether features ofthese industries, or of the product development
strategies they have used, could be adopted by
the nuclear industry to reduce the high cost andlong time to deployment associated with new
nuclear technologies. Although most of the survey
subjects represented multibillion-dollar industries,
their business models varied substantially andincluded some aspects that were relevant for
the nuclear energy industry. The industries wesurveyed are pictured in Figure 2.1 and groupedin terms of common features.
A comparison of these features and of estimateddeployment timeframes and costs (discussed
in Appendix G) indicates that nuclear energy
compares poorly to most other technologyintensive industries. This is likely due to a
combination of factors, including the large scale ofnuclear projects, high levels of regulation-driven
research and development (R&D) and extensive

Chapter 2: Nuclear Power Plant Costs

31

Figure 2.1: Major industries grouped by four key features: physical scale of theasset (beige); scope and rigor of applicable regulations (green); efficiency infabrication and supply chain (blue); high added value of the product (white).

Coal
PlantsOffshore
Oil and Gas

High Returns$

Large Scale

Nuclear
PlantsChemical
PlantsExtensive R&D
and Rigorous
RegulationDriven Testing

Satellites

Jet Engines

Pharmaceuticals

Factory Fabrication,
Modular Construction,
Strong Supply Chains

Automobiles

Robotics

Advanced
Nuclear

18-GA50013-01

Nuclear power currently has a unique combination of features that adversely affect its cost and time to commercial
deployment. The challenge for new nuclear systems is to move from the top left corner of this chart to the bottom
right corner. Taking advantage of factory fabrication, modular construction, and a strong supply chain could help
shorten the innovation cycle for nuclear technology and improve the industry’s economic returns. The introductionof a price on carbon emissions would make all non-carbon energy sources more competitive and create added value
for nuclear power plants.

testing requirements to license new facilities,
inefficient construction practices, and the
low-value-added nature of the product nuclear
energy supplies (i.e., electricity). The role of thesecost drivers for nuclear energy in comparison toother industries is summarized below.

Large Scale
Several industries build facilities (such as chemicalplants, oil refineries, coal plants, and off shore
oil platforms) that are similar in scale to nuclear
power plants, are likewise highly engineered,and thus require significant planning and project
management during the construction phase. The
development cycle for these large, constructionbased industries (chemical, offshore oil and gas) issimilar to that for nuclear power in that it involves
a progression from R&D to small-scale prototype
to large-scale pilot plant and eventual commercial

32

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

offering. Nonetheless, typical timeframes for thisdevelopment cycle are somewhat shorter in theseindustries than they are for nuclear power. Other
industries (e.g., robotics, automotive, and coal)
have much shorter product development timelines
and operate in very competitive markets. They
integrate all key functions at the start of a project
to design a product (and associated systems andsubsystem parts) to meet a stringent cost target,with a total project schedule from conception to
product of 18 to 36 months.
Many of the industries we surveyed are capitalintensive. Jet engine development, for example,
is very expensive. The cost of a jet engine is notrecovered on the sale of the engine but rather onservicing it once it is in use on an airplane. This issimilar to nuclear power. Reactor sales are rarely
profitable but fuel and services are.

Extensive Regulation-Driven R&D
and Rigorous Testing
Like the nuclear energy industry, the jet engine andpharmaceuticals industries face extensive R&D
and rigorous testing requirements to license theirproducts because of the potential consequences
associated with the use of these products. In the
United States, the drug trial program for new
pharmaceuticals is intensive and expensive;
to be approved, new products must be tested
according to detailed protocols defined by the U.S.
Food and Drug Administration. In the case of jet
engines, detailed regulations guide the types oftesting that must be performed, including testing
prototype engines under extreme conditions.
Licensing a nuclear reactor likewise requires avery complete understanding of the reactor—thedifference is that it is often difficult to test nuclear
systems except at scale, which makes productdevelopment more expensive for the nuclear
industry. In both the jet engine and automobile
manufacturing industries, computation models
have evolved enough to give companies theengineering confidence to enable performance
testing at full scale. Some of the other industries
are self-regulated and some only require testing
to demonstrate regulatory compliance forparticular attributes of the final product (e.g.,compliance with emissions limits). Nuclear energy,
by contrast, is subject to regulation during allphases of product development and deployment:
during design, during construction, and during
operation. Regulatory oversight includes reviewing
the fabrication of key components and testing
key systems on site, as well as monitoring during
operation, all of which add to cost.

Inefficient Construction
Some of the industries we surveyed use factoryfabrication and modularity in construction/assembly to reduce both cost and deployment
time. The nuclear industry, however, typicallydoes not. Manufacturers of jet engines andairplanes, for example, leverage the economies
of serial production in the assembly of aircraft.
Barriers to entry in that industry are high, so
only a few producers are in the market. In otherindustries, such as automobile manufacturing,parts standardization is critical and factoryfabrication is highly optimized to enable mass
production at many facilities around the world.
To be profitable and to recover the $3–$5 billion
investment associated with developing andproducing a new model vehicle, a car company has
to have product sales in the tens of millions. The
auto industry relies on strong supply chains forparts, electronics, and other components to makestandardized mass production in factories viable.

Insufficient Value Added
Many industries we surveyed produce high-valueadded products. For example, with a new drug, thepharmaceutical industry garners significant value
in each step of the development and deployment
trajectory. The process is lucrative in part because
new drugs often enjoy a natural monopoly: there
is no substitute or alternative source for the same
product. By contrast, nuclear energy producers
are in a competitive market for a commodity(electricity) where it is difficult to receive full value
for the attributes of their product. The industry’s
ability to change its development and deployment
trajectory in ways that enhance value creation isconstrained by the current electricity market.
For all of these reasons, the ability of the nuclear
energy industry, as presently configured, toinnovate over its product development cycle islimited compared to other technology-intensive
industries. Several features of the industry areworth underscoring in this regard: (a) current
nuclear power plants are very large facilities
that require a massive investment to deploy; (b)these plants, rather than being manufactured
in factories, are constructed and assembled
in the field, making it difficult for the industry
to invest in delivery models that could benefit
from substantial advances in productivity andthus reduce costs; (c) licensing a new nuclear
facility requires lengthy R&D and rigorous
testing; (d) nuclear energy’s unique quality,
safety, and security requirements relative toother energy technologies necessitate costly
systems, structures, and components that must
be designed to survive extreme external eventsand natural phenomena (e.g. earthquakes, airplanecrashes, floods, hurricanes) and mean that the

Chapter 2: Nuclear Power Plant Costs

33

industry’s operations are highly regulated; and (e)the industry’s product (electricity) is a commoditywith many alternative suppliers and low added
value. This combination of characteristics has
resulted in long lead times (20–30 years) andhigh cost ($10–$15 billion) to bring new reactor
technologies to market. These characteristics also
make the nuclear energy industry very risk averse,
which can stifle innovation and slow the potential
to learn from other sectors. Later sections of
this chapter, and later chapters in this report,
discuss the changes required to remove current
roadblocks to innovation and growth in the nuclear
energy industry.

2.2 REACTOR TECHNOLOGY COSTSThis section discusses the critical cost challenges
that confront nuclear power. We begin byexamining light water reactor (LWR) costs aroundthe world since these provide a true baseline forthe construction and operating costs of a nuclear
system. We then take a close look at the major
contributors to this baseline cost.

Basics of Power Plant Cost
There are three basic components to the cost of
a new power plant that produces electricity (orany other energy product), whether the plantuses nuclear technology or any other technology:
capital cost, operating cost, and fuel. Capital cost
is composed of two parts: (a) the ‘overnight cost,’
which refers to the cost of building the plant,
including equipment, construction materials, andlabor, independent of how long it takes to actuallybuild the plant (hence the term ‘overnight’) and(b) the cost of interest on funds raised to build
the plant (either as loans-debt or stock-equity).
Interest cost is affected by the time required toconstruct the plant and the composite interest rateof the funds used. This financing cost is termed
either ‘interest during construction’ (IDC) or‘accumulated funds during construction’ (AFDC).
Once a plant is built, operation and maintenance(O&M) costs depend on the personnel needed
and the consumables used to run the facility.
The final major cost component is the cost of thefuel used to produce the electricity. Capital andoperating costs can be considered fixed costs that34

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

are incurred whether the plant produces electricity
or not, although operating costs do have a variable
component that is affected by workforce changes,
training needs, and materials used. Fuel costs,
by contrast, are wholly variable since they are
incurred only when the plant is operating.
Nuclear energy technology is capital-intensive.
Depending on the plant, capital cost can accountfor more than 80% of the cost of energy froma new nuclear plant, with the remainder of thecost typically divided between O&M costs (15%)
and fuel costs (5%). These percentages canvary somewhat for different plants depending
on interest rate, actual construction time (which
affects the amount of interest paid), and thenature of contracted engineering services. Notethat this cost structure for nuclear plants is quite
different from that for a natural gas plant, where
80% of the cost is the fuel cost. Appendix K
provides more explanation of these costs withsome simple examples.

Historic Experience with LWR Construction
Figure 2.2 displays overnight construction costs
in 2017 dollars per kilowatt of electrical generating
capacity (kWe) installed for LWR plants aroundthe world. The figure includes older plants andplants that have been recently completed or
proposed, or are under construction (Lovering, Yip,and Nordhaus 2016). Costs for nuclear builds in
China are estimates from Ganda (2015) and theWorld Nuclear Association (2018). South Koreancosts are from Chung (2018). Cost data for EPR
and AP1000 reactors and for the U.A.E. project arefrom press reports, as discussed in Appendix H.
The basis for these costs may not be the samein different countries. For example, the pricenegotiated for a given plant may not represent
the actual cost because of direct or indirectgovernment subsidies. Some of the cost data are
for FOAK units, while others are clearly for more
standardized, ‘nth-of-a-kind’ (NOAK) offerings.
Some are for single-unit plants and some are formulti-unit plants. Some are only estimates forplants that are yet to be built. Financial markets
are also different in different countries. Of greatest
concern are data from the Chinese and SouthKorean builds, where a lack of transparency anddetail makes it difficult to scrutinize and validate
available cost estimates. For example, there issome uncertainty in the cost of the South Koreanbuild in the United Arab Emirates because it may
not include all of the owner’s cost (see Appendix
H). Nevertheless, we include the U.A.E. estimate
because of the construction discipline that
South Korea has shown in its reactor builds, both
domestically and now in the Emirates.
The range displayed in Figure 2.2 is quite large
and extremely variable. The lowest costs being
reported today are in South Korea and China, andfor the U.A.E plant that is being built by South
Korean engineering companies. Costs for current
Western plant designs (i.e., the EPR and AP1000)are significantly higher than for other types ofreactors, in part because of many FOAK issues
associated with the hiatus in nuclear constructionin Europe and the United States over the last three
decades. For existing plants, the lowest costs are
in South Korea, India, and France, followed by
Japan and the United States. The older U.S. LWR
fleet shows a large range in cost, in part becauseof the significant turbulence in electricity demand,
construction delays, and regulation (following theThree Mile Island accident) that characterized thelate 1970s and 1980s.
The stubbornly high capital cost of new nuclear
plants, along with lengthy construction delays, isa major factor in the dim outlook for new nuclear
power plant construction in the United Statesand Western Europe. Both the original 2003 MIT

Future of Nuclear Power study and a 2009 updatestressed the impact of these factors, and thesituation is only worse today. The early historyof plant construction in the United States wasplagued by significant construction delays andcost overruns. New Generation-III+ (Gen‑III+)
reactor designs were intended to reduce
construction costs, and improve other aspects ofeconomic and safety performance. In assessingthese new designs, the authors of the 2003 MIT
study wrote “...plausible reductions by industry incapital cost, operation and maintenance costs, andconstruction time could reduce the [competitive]
gap. We judge the indicated cost improvements
for nuclear power to be plausible, but not proven”(Deutch, Moniz 2003). The 2009 update asked,“Will construction proceed on schedule andwithout large cost overruns? The first few U.S.
plants will be a critical test for all parties involved”(Deutch, Forsberg, et al. 2009).
Actual experience with the first few new buildsof Gen-III+ designs in the United States andWestern Europe failed that test spectacularly. Allof the projects have experienced long delays andlarge cost overruns. Figure 2.3 shows the latest
estimated overnight costs for the first five builds
in the United States and Western Europe against
the target benchmark proposed in the MIT 2009
update report. The left three bars on the figure
show the cost for the first three European buildsof the EPR, a pressurized water design that was
created by a joint venture of Framatome (thena subsidiary of Areva), Siemens, and Électricitéde France (Framatome has since been sold toFigure 2.2: LWR construction costs around the world

Overnight Cost (2017 $/kWe)

14000

Recently Completed, Proposed or Under Construction

Historic Plants

12000
10000
8000
6000
4000
2000
0

US '68-'78

France '71-91

India '76-'90

South Korea'89-'08

Japan '80-'07

South Korea UAE APR-1400
APR-1400

China

US AP1000

UK EPR

France andFinland EPR

Chapter 2: Nuclear Power Plant Costs

35

Figure 2.3: Overnight cost of recent Gen-III+ builds versus benchmark
10,000Overnight Cost ($/kW 2017)

9,000
8,000
7,000

MIT 2009 Update
Benchmark

6,000
5,000
4,000
3,000
2,000
1,000
0

Olkiluoto Flamanville Hinkley C

Vogtle 3&4

Électricité de France and Areva has been renamed
Orano). The next two bars show the cost for thetwo U.S. builds of the AP1000 design, created byWestinghouse (Westinghouse was once owned
by Toshiba, recently went through bankruptcy,
and has since been purchased by Brookfield
Asset Management). Of these two, the V.C.
Summer project was recently canceled due to cost
overruns. The final bar is for the South Koreanbuild currently underway at the Barakah site in the
United Arab Emirates; as of this writing, the firstreactor unit at that site is nearing completion, but
has recently announced a delay of one year for
operational readiness reasons. As noted earlier,there is uncertainty about the U.A.E. cost figures,
thus the bar is colored differently in the figure.

Comparisons to Other Energy Sources
For this part of the analysis we compared levelized
costs of electricity (LCOEs) for natural gas,coal, and advanced LWRs in OECD countries,
China, and South Africa using information fromthe Nuclear Energy Agency (2015). Consistentassumptions were used to calculate these LCOEs:
specifically, a discount rate of 7%, a capacity
factor of 85%, and a carbon price of $30 per
metric ton of carbon dioxide (CO2) for all threeenergy systems. Assumed natural gas costs were$5.50 per million British thermal units (MMBtu)
in the United States, $11.10/MMBtu in Europe, and$14.40/MMBtu in Asia for liquefied natural gas

36

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

V.C.
Summer
2&3

Barakah(UAE)(LNG). However, significant reductions in the priceof natural gas have occurred since the Nuclear
Energy Agency report was published. As of thiswriting, the cost of natural gas in Europe is at$5/MMBtu; in Asia it is $7/MMBtu. Table 2.1
compares normalized levelized costs in the UnitedStates, South Korea, China, Japan, and France.
For each country, absolute cost values werenormalized to a value of 1.0 for LWRs. Thus, if
the normalized value is less than 1.0 that energy
option is more competitive than nuclear and if it
is greater than 1.0, nuclear is more competitive.
Normalized values cannot be compared acrosscountries. For natural gas a range of LCOEs isshown based on today’s actual, lower natural
gas costs and the higher values used in theoriginal analysis.
As discussed in Chapter 1 and shown in thetable, without a carbon constraint, nuclear does
not appear economic compared to other energy
sources and cannot supplant cheap natural gas in
the U.S. context. A recent study found that nuclear
overnight costs would have to be between $2,000
and $4,000 per kWe to be competitive withnatural gas when natural gas prices are between
approximately $3.50 and $4.75 per MMBtu(U.S. Department of Energy 2016).
In Asia, LWRs are generally competitive withcoal and natural gas when a carbon constraint
is imposed, but at lower natural gas costs

Table 2.1: Normalized LCOEs for natural gas, coal, and nuclear in different countries with different costsof natural gas
Natural Gas

Coal

Nuclear

LCOE

LCOE with Carbon Costa

LCOE

LCOE with Carbon Cost

0.67

0.85

0.88

1.21

1.0

South Korea

1.54–2.69

1.78–2.93

1.40

1.99

1.0

Japan
China
France0.92–1.46
0.74–1.72
0.58–1.05

1.05–1.58
0.97–1.95
0.71–1.18

0.94
1.03
–

1.23
1.63
–

1.0
1.0
1.0

US

a

LWR

Assumed carbon cost is $30/tonne of CO2

the competitiveness decreases substantially,
especially in China and Japan. In Europe, without
a carbon constraint, natural gas is less expensive
than nuclear. With a carbon constraint, LCOEs fornuclear and natural gas are similar.
Finding:

New nuclear plants are not a profitable
investment in the United States and Western
Europe today. The capital cost of building
these plants is too high.

2.3 ROOT CAUSES OF NUCLEAR
PROJECTS’ HIGH COSTS
A number of well-known factors explain mostof the wide range of costs in Figures 2.2 and 2.3,
none of which are inherent to nuclear technology.
FOAK plants in any country are typically 30%
more expensive than subsequent plants of thesame design. This ‘cost of learning’ is likely to beeven higher if the firm/industry responsible forconstruction has not built any new plants in a
generation and so must rebuild or relearn all of theexpertise and how-to knowledge that is required.
In addition, delays, rework, supply chain issues,and other factors that extend the construction
schedule can further increase the cost, even before
considering interest costs. FOAK, single units, or
projects with a smaller number of units per site,
also have to carry the full costs of licensing a
new reactor as well as any site development andinfrastructure/mobilization costs. The AP1000
in the United States and the EPRs in Finland,
France, and the United Kingdom all fit this pattern.
By comparison, the most cost-effective plants

have been built with multiple (up to six) units
per site using a standardized design (Lovering,
Yip, and Nordhaus 2016), with the same vendors
and workers working on each unit, and with acontinuous build. This avoids additional costs formobilization or to restart component production
and maximizes learning for process improvement.
This has been the approach in South Korea
and, earlier, in France. A recent example of thisapproach is the Barakah project in the United ArabEmirates, which experienced a 40% reduction inlabor costs between the construction of Units 1
and 4. Nuclear plants started off in China, Korea,
and Japan being fairly expensive, but with very
concerted efforts at cost reduction and schedule
improvement, learning over time has reduced theircosts relative to those of earlier plants. Figures 2.2
and 2.3 tell the story of two sets of projects: one inwhich all the factors that can significantly drive up
costs were active, while almost none of the driversof cost reductions were present; and a second
set in which the reverse was true: cost-increasing
factors were absent, while cost-reducing factors
were in force.
Other features related to the execution of large
complex construction projects also help to explain
the cost differences seen in Figures 2.2 and2.3. First, lower labor rates in China and South
Korea make it cost effective to maintain large
construction staffs on site, which allows juniorworkers to shadow senior workers in the mannerof an apprenticeship and gain relevant training for
future projects. (Differences in labor wage rates
among various countries are discussed in the next
section.) Second and perhaps more important,recent project experience in the United Statesand Europe has demonstrated repeated failuresof construction management practices compared

Chapter 2: Nuclear Power Plant Costs37

to projects in China, South Korea, and the United
Arab Emirates. Finally, strong government support
in the latter countries was critical to the success of
their nascent nuclear power industries.
Interviews with managers of construction projects
in the United States (i.e., Vogtle) and overseas(i.e., in Europe and at the U.A.E. Barakah site)
point to several project attributes that seem tocorrelate with success or failure.
Finding:

Successful nuclear builds tend to have thefollowing attributes:a) Completion of needed portions of thedesign prior to start of construction,*b) Development of a proven supply chain

for nuclear steam supply system(NSSS) components and a skilled labor
workforce,*c) Inclusion of fabricators and constructors

in the design team to ensure thatcomponents can be manufactured
and structures can be built torelevant standards,d) Appointment of a single primarycontract manager with provenexpertise in managing multiple
independent subcontractors,

This finding echoes recommendations made by
the Institute of Nuclear Power Operations (2009)
when that organization, anticipating a renaissanceof investment in nuclear energy, sought to identify
the characteristics of successful new builds.
Notably, many of these attributes were also absent
in the effort to build a new AP1000 reactor at
the V.C. Summer site, as Bechtel (2016) noted in
an independent assessment of that project (theBechtel assessment was conducted 18 months
prior to the project’s cancellation, but its findings
only became public in late 2017).
When these attributes are missing in a newbuild, the result is a loss in productivity on thesite and the need to rework and/or redesign
aspects of the project, all of which are likely tocause delays and interfere with efficient project
execution. These delays and changes in turnripple through the entire project, often causing
significant cost increases because of the additional
accrual of interest on what are typically very large
construction loans while any issue is resolved.
Recommendation:

Focus on using proven project andconstruction management practices toincrease the probability of success in theexecution and delivery of new nuclear
power plants.

e) Establishment of a contracting

structure in which all contractors (andsubcontractors) have a vested interest in
the success of the project,f) Adoption of contract administrative

processes that allow for rapid andnon-litigious adjustments to unanticipatedchanges in requirements or subcontractor
performance, andg) Operation in a flexible regulatoryenvironment that can accommodate
small, unanticipated changes in designand construction in a timely fashion.
* Note that attributes (a) and (b) are typicalissues for FOAK projects.

38

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

2.4 A BREAKDOWN OF NUCLEAR
ENERGY CAPITAL COSTS
Setting aside project execution issues, it isimportant to understand determinants of theovernight capital cost of a new nuclear power
plant. Table 2.2 breaks down this cost by major
component for a generic AP1000 (Black & Veatch2012), for historic U.S. LWRs, and for the South
Korean APR1400 (Kim 2016) and the French
EPR (de Toni 2017). For historic U.S. LWRs, thetable shows two figures: the best plant (Ganda,
Hansen, et al. 2016) and a median plant (Lucid
Strategies 2018) based on detailed historic costs

Table 2.2: Cost breakdown for various LWRs
Cost Breakdown (% of total cost)
Historic U.S. LWR
Historic U.S. LWR
South Korean
Median CaseBest Case
APR1400
9.9
16.5
21.9

Nuclear Island Equipment

Generic
AP1000
12.6

Turbine – Gen. Equipment

4.9

7.0

11.9

5.6

6.3

Yard, Cooling, and Installation
Engineering, Procurement,
and Construction Cost
Owner’s Cost

47.5

46.3

49.3

45.5

49.7

15.9

17.6

7.7

20.0

15.3

19.1

19.2

14.6

7.0

10.7

from the U.S. Energy Economic Data Base (1986),
with costs for individual labor components andmaterials escalated to current dollars.
The costs in Table 2.2 are disaggregated into
five major categories following the accounting
breakdown used by Black & Veatch (2012):• Nuclear island equipment includes physicalequipment for the nuclear island (e.g., reactor
vessel, piping, steam generator).
• The turbine generator equipment is thesecondary side of the plant.
• The category termed ‘yard, cooling, andinstallation’ includes costs for civil works to
prepare the site, including excavations andfoundations, the ultimate heat sink (cooling
towers or river cooling), other equipment, andthe installation of plant components.
• Engineering procurement and construction
costs are related to indirect engineering,
quality assurance (QA), and supervisory
costs for engineering, procurement, andconstruction (EPC).
• Owner’s cost includes fees and permits, taxes,
owner’s engineering costs, and costs for spareparts and commissioning.
Interest during construction, which is the costfor carrying the loan prior to plant operation, is
not included for two reasons: (a) it is not part ofthe overnight cost and (b) large differences inconstruction times and associated financing costsin the United States and South Korea would skew
the comparison.

EPR
18.0

Several points emerge from an examination of thecost components shown in Table 2.2: First, thereactor and power conversion system equipment
represent only 17%–28% of total cost. The
remainder of the cost comes from site preparation,
installation of components and associated field
and home engineering, and owner’s costs. Basedon a more detailed breakdown of historic data on
median LWR costs, direct site labor and field andhome engineering are about 60% of the total cost(or about 75% of non-equipment costs). If interest
costs during construction are included, the fractionof total cost associated with the nuclear reactor
and turbine islands is even smaller because thelong construction times in the United States resultin significant interest payments.
Finding:

Cost reduction efforts need to be focused
not on the NSSS design or the specificreactor technology but on (a) improvements
in how the overall plant is constructed(or delivered to the site), and (b) ways
to accelerate the construction process
to reduce interest costs during this period.

Labor Rates and Labor Productivity
Labor costs account for a large part of the capital
cost of building a nuclear power plant. Overnight
costs differ by country or across different regionsof the world in part because of large differences in
the wages paid to construction workers (Bureau ofLabor Standards 2012) (Richardson 2016) (World
Salaries 2008) (The Conference Board 2016),

Chapter 2: Nuclear Power Plant Costs

39

as indicated in Figure 2.4. Although different
sources report different absolute hourly
wage rates, in part because they use different
methodologies to calculate average wages, thedata show that labor costs in Europe range fromabout 50% to 160% of U.S. costs, with mostsources citing costs within 50% to 80% of the
U.S. average. In South Korea, by contrast, laborcosts are about 55% of the U.S. average and in
China they are even lower, just 5% to 18% of the
U.S. figures.
We performed our own assessment of labor rates
at nuclear construction sites around the world
for professionals (Appendix I provides details on
the methodology), including field supervisors,
engineers and technicians with different levelsof experience and skill, and administrators.
Their hourly rates are shown in Figures 2.5a and b.
Average hourly rates from the different countries
with appropriate overheads were then used toestimate the cost of building the best and median
U.S. LWRs based on the U.S. Department ofEnergy (DOE) code of accounts and the numberof hours associated with each plant component,
as given in the U.S. Energy Economic Data Base(1986). Overall construction labor costs areshown in Figure 2.6. The cost of South Korean andChinese labor is respectively about $400/kWe
and about $900/kWe less than the U.S. labor cost,which is generally consistent with the construction
database estimates from Figure 2.4. South Korean
labor cost is about 50%–60% that of the U.S.
figure, while French construction labor rates areapproximately 60%–80% of those in the UnitedStates and Chinese labor rates are less than 20%of the U.S. rate. These analyses suggest thatwhile differences in labor rates play an importantrole, they do not account for all the variation in
overnight construction costs observed in nuclear
plant projects around the world.
Beyond wage differences, the actual laborproductivity of construction workers in different
countries is important. Figure 2.7 plots changes in
U.S. labor productivity for a number of industries
over time from a study by McKinsey Global
Institute (2017). It shows that labor productivity in
the U.S. construction industry has declined relative
to other industries, including manufacturing,which saw an eight-fold improvement in laborproductivity over the same period due in large partto automation. This lack of productivity growth

Hourly Construc=on Labor Costs Rela=ve to US (= 1)

Figure 2.4: Construction labor costs in different regions of the world

1.80

BLS,2012

1.60

Richardson Intl Construc<onFactor (2007)

1.40

Hourly Compensa<on Index

1.20

World Salaries

1.00
0.80
0.60
0.40
0.20
0.00

40

US

ENGLANDFRANCEJAPAN

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

SOUTH
KOREA

CHINA

Figure 2.5a and b: Hourly wages for a variety of professionals involved in nuclear plant construction
$100
$90

USA

$80

South Korea$70

France

$60

China

$50
$40
$30
$20
$10
$0

Professional
engineer(highest)

AdvancedengineerIntermediateengineer

Elementaryengineer

Highly Skilled Intermediatetechnician
skilledtechnician

Elementaryskilledtechnician

$100
$90

USA

$80

South Korea$70

France

$60

China

$50
$40
$30
$20
$10
$0

Field
Supervision

Engineering Structural Craft Mechanical Electrical / I&C Construction Other NonCraft
Craft
Services
Manual Labor(Admin)Figure 2.6: Estimated labor cost for building the best and median U.S. LWR in different countries$1,200Labor Cost ($/kWe)$1,000
$800
$600
$400
$200
$0

US

South Korea

FranceChina

Chapter 2: Nuclear Power Plant Costs

41

Figure 2.7: Labor productivity in the U.S. for a number of industries in the past half-century(McKinsey Global Institute 2017)

in the construction industry is also observed
globally, especially in wealthier countries like
Japan, Germany, France, and Italy (The Economist
2017a). By comparison, labor productivity
has been growing in South Korea and China
compared to the United States and most of Europe(McKinsey Global Institute 2017).
Changes in plant design during construction,
whether for regulatory, quality, or owner-induced
reasons, as noted earlier, compound the impactof these differences. Thus, we conclude that incountries or regions where construction labor rates
are high and productivity is low, new construction
techniques (for example, greater modularity,
which we discuss in the next section) will benecessary to reduce overall labor requirements
and reduce construction time and cost. Further
improvements in construction productivity shouldbe pursued through automation, data collection,
and analysis—potentially useful tools are available
to assist in all these areas (Rhumbix 2017).

42

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

2.5 STRATEGIES FOR COST
REDUCTION AND REVENUEENHANCEMENT
Detailed cost breakdowns for LWRs, as well as
for the high-temperature gas reactor (HTGR),
a low power density, high-pressure design, andsodium-cooled fast reactor (SFR), a high-power
density, low-pressure design (Appendix K), showthat the nuclear reactor and turbine islands do not
dominate the costs of these advanced systems.
Costs are dominated by civil works, structures,and buildings; electrical equipment installation;
and associated indirect costs for this work on site.
Cost reduction strategies focusing on these items
should be most fruitful. We examine the potential
to achieve cost reductions and/or revenue
enhancement by changing how the reactor isbuilt, standardizing reactor design, reducing
commodity use, and incorporating technology
advances from other fields that are applicable
to nuclear power. Our goal in examining thosecrosscutting technologies is to determine if they
have significant capability to reduce the capital,
fuel, and/or operating costs associated with
nuclear power, or to increase the revenue nuclear
plants produce. We also attempt to quantify

these benefits to the degree possible. Table 2.3
summarizes the technologies considered and theireconomic benefit. Further detail can be found inChamplin (2018). Although the table lists all thetechnologies we considered, only those identified
to have the highest impact are included in thediscussion that follows.

Advanced Construction Techniques:
Modularization and Factory or
Shipyard Fabrication
Historically, cost overruns in nuclear power
plant projects were associated with changes inplant design during construction. Whether thesechanges were prompted by regulatory, quality,or owner-induced considerations, they increased
direct and indirect labor requirements and delayed
the overall construction schedule (Ganda 2016).

In many cases, construction productivity was
impaired because the large on-site work force
would be left idle while changes rippled throughthe re-engineering process, licensing review, andconstruction. Comparing best and median LWR
experiences suggests that the range of indirect
costs from project to project can be quite large.
The historic database does not provide any dataon the linkage between direct and indirect costs
but begs a key question:
Are there ways to reduce both direct andindirect costs by changing the way systems
are delivered to the site?
The answer to this question may lie in theextent to which nuclear plant construction canbe modularized. Modular fabrication and/or
construction techniques can be employed on

Table 2.3 Summary of Major Crosscutting Technologies and their Benefits
Technology

BenefitAccident Tolerant Fuels

Depending on reactor design, these fuels can mitigate the consequences of severe accidents and canenable downgrading of safety-relevant equipment and reduction of associated O&M costs.

Additive
Manufacturing

Useful for difficult-to-make parts. Allows for faster/cheaper prototyping. Reduces waste in
fabrication.

Advanced Concrete

Automated/Prefab
Functionalized
Steel Plate Composite: Eliminates formwork and reduces rebar; 50% less installation time; 25% lessconcrete and steel
Ultra-High-Performance Concrete: Similar impact as steel plate composite
High-strength Reinforcement Steel: Reduces rebar amount by as much as 40%

Advanced Construction
Techniques

Modular Construction in Factories and Shipyards: 10–20% less capital and shorter construction time

Advanced Siting
Options

Standardization and Multi-unit Sites: Key role in reducing cost because it enables faster learning byconstruction crews, thereby enabling economy of replication.

Optimized Power Conversion System Layout

Seismic Isolation: Enhances plant standardization; ≈5% less capital
Embedment: Protects against design basis threats. Reduces size and cost of shield building, reduces
seismic load.
Offshore siting: Enables shipyard construction and efficient delivery of an entire nuclear plant.
Advanced Power
Conversion

Air or Helium Brayton: higher efficiency to reduce overnight cost

Coatings andNano-textured
Surfaces

Hydrophobic in condensers: +1–2% efficiency

Instrumentation andControl Technologies

Improved operational efficiency and reduced uncertainties in key plant parameters (core power,
thermal margin, fuel burnup and radiation damage).

Robotics

Replace humans with robots in difficult environments (radiation, confined space, temperature, highhumidity) in operations, maintenance, and emergency response.

Energy Storage

Enables modulation of electric output to the grid without affecting power of the reactor.

SCO2 Brayton: higher efficiency to reduce overnight cost
Hydrophilic in steam generator: +0–1% efficiency
CRUD repellent: Saves ≈ $1–$3 million/reactor-year(bold font designates those technologies with the highest cost-reduction potential)

Chapter 2: Nuclear Power Plant Costs

43

engineering systems of all sizes and scales. For
example, both automobiles and jet engines arebuilt in a modular fashion in factories but theirsizes are quite different. Thus, nuclear reactorsof all sizes can employ modular fabrication/
construction techniques to varying degrees,
depending on the design of their specific systems
or subsystems.
In recent years, other large industries and partsof the nuclear industry have used modularityand factory or shipyard fabrication (also termed
advanced manufacturing or advanced construction
techniques) to reduce on-site labor. Components
are assembled into larger modules at existing
factories or shipyards and are shipped to thebuilding site with reduced installation time. The
number of modules and the size of each module
are dictated by the transportation alternatives(barge, truck, train, airship) available fordelivering them to the site. Based on experiencein the chemical industry, a range of options isavailable and in use today. Thus, modular factory/
shipyard assembly offers a different approachto construction, essentially turning nuclear
components into a product suitable for mass
production and delivery versus a customized
process that builds on site. The objective of thisnew delivery paradigm is a net reduction in on-sitelabor requirements, in associated home and fieldengineering costs, and in the time required tocomplete construction.
Modularity is already being used effectively
by other heavy industries including for theconstruction of chemical plants, offshore oil andgas platforms, and LNG plants (Fluor 2017),(Epic Process Systems 2017), (Brookfield andCooke 2011). Module sizes can vary from barge/
ship-mounted modules, skid-mounted modules
for equipment, modules that fit on trucks, andintermediate (100-ton modules) to very large
modules (600 tons). Modular building, onland and at sea (in the marine industry (The
Economist 2017 b)) has been found to accelerate
construction and enhance overall construction
productivity. Large gains in productivity havebeen attributed to investment in machines rather
than labor as projects have become larger and44

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

more complex. Results have included dramatic
cost reductions for dredging and constructing
offshore oil platforms as the speed and quality ofwork has increased. Modularity is also occurringin the electrical cable industry (Eby 2010), which
is using prefabricated and pre-tested electricalcomponents and modular wiring systems.
Finally, the chemical manufacturing industry
is increasingly adopting modular fabrication
techniques (European Commission 2014).
Studies suggest that these techniques can enablesignificant reductions in capital cost (20%), time(40%), and labor (25%–50%) (De La Torre 1994).
Some researchers have examined the effect ofmodularization on the economics of small nuclear
reactors (Locatelli, et al. 2016) (Boarin, et al.
2014) (Maronati, et al. 2018). Small reactors
suffer from a lack of economies of scale (relative
to large LWRs) but the research suggests that thisdisadvantage could be balanced by the economies
of multiples. Modularizing small reactors would
enable shop, factory, or shipyard fabrication;
standardization; and accelerated learning ascomponents are repeatedly factory manufactured
for multiple reactor orders. In addition,
modularization would divide the total capital
investment (and associated risk) of a project into
smaller pieces, thereby reducing construction timeand interest costs during construction. The hopewould be that all these factors, taken together,would offset the penalty associated with a lackof economies of scale. A compelling case can bemade for this approach, but it has yet to be provedin practice by the nuclear industry.
Some of the earliest ideas on modular construction
for the nuclear industry were reviewed in 2004
(Schlaseman 2004). A number of then novel
construction techniques were evaluated andused by reactor vendors on large LWRs. For
example, modularization was used successfullyin the construction of numerous subsystems
and large parts of LWRs in Japan—extensively
in that country’s fleet of advanced boiling water
reactors (ABWRs)—and to a lesser extent in
China, India, and South Korea (Presley and Weber2009) (Nuclear Energy Agency 2015) to reduce
construction time. In Japan, ABWR constructionschedules were reduced by nearly 20% andnon-civil construction person-hours were reducedby nearly 40% relative to experience with newreactor construction prior to the ABWR buildout(Tuohy and Yonemura 2008). As a result, theseplants had some of the shortest construction times
for LWRs around the world. In the new pressurized
heavy water reactor design being deployed inIndia, preassembling the entire calandria/core
package is believed to save 10–12 months in theoverall construction schedule (Vhora 2018).
More current experience in the United Statessuggests that the cost savings being achieved
through modularization are only about 10%–15%compared to the larger values seen in otherindustries and in nuclear projects in othercountries. For example, modularization techniques
were applied to some subsystems and structuresof the AP1000 (Deng 2011). Components andsupports were delivered to the construction site,
assembled into larger modules in a dedicatedon-site building, and finally lifted into their final
location. Self-consolidating concrete was also
employed in many places. The expectation wasthat this approach would do more to reduce
construction time (and associated cost) than it
would do to reduce actual labor requirements(O’Connell 2017). However, Westinghouse has
had both positive and negative experiences withmodularization in the AP1000 reactor. Much of thecompany’s negative experience has been related
to FOAK issues. Westinghouse believed that theconstruction schedule for the AP1000 could be
reduced to 30% that of the Vogtle unit based onprior learning. Furthermore, the company has
stressed the importance of a judicious approach
to modularization. In some cases, traditional
stick-built structures are less expensive, especially
if they are not very complex and can be efficiently
fabricated and installed on site.
NuScale, a U.S.-based vendor of SMRs, is also
employing modularity for their reactor system,rooms containing ancillary equipment, and othernon-nuclear systems. Using chemical experiencein modularity from Fluor, NuScale expects
overnight cost savings of about 10% but moresignificant reductions in construction time (andassociated financing costs) as well as increased
confidence and certainty about the schedule forproject delivery since higher-risk components will
be assembled in the factory (Perez 2017).
By contrast, the experience of Newport News
Shipbuilding and Electric Boat in building nuclear
submarines (Mills 2017) has provided a morestriking demonstration of the potential for
improvements in construction efficiency, showingthat a task, such as performing a weldment,that requires one person-hour to complete ina modular fabrication shop will require three
person-hours at an open site in the field (such as
an assembly platen) and eight person-hours at
the final location (in this case, a dry dock). Thisis widely known at Newport News Shipbuilding
and Electric Boat as the ‘1-3-8 rule.’ The reason
for this dramatic difference in labor and cost for
tasks performed in the shop compared to thefield is that the processes, procedures, access,tooling, workforce proficiency, and environmental
controls in place in a shop setting provide the mostefficient environment for completing the work.
Modular design and construction save time andmoney by moving portions of the work to centersof skilled labor, instead of requiring skilled workers
to perform under more difficult conditions on site.
This also improves product quality and worker
safety and reduces the number of tradesmen as
well as the average skill levels required on site,with corresponding reductions in on-site laborcosts. Like automobile assembly plants, factories
used to produce nuclear system components
should also be designed for maximum automation
to reduce labor costs as much as possible.
To make the most of its advantages,
modularization must be considered at theconceptual design stage, especially for the moremundane parts of plant design that involve
buildings, rooms, structural concrete, electricalconduit/cable trays, and piping runs. However,there are drawbacks to modularity. Engineering
limitations of this approach include tolerance
stack-up effects, increased work to connect
modules, and the need to assure structural
integrity of the module during transportation
to the site. In fact, the g-forces associated with

Chapter 2: Nuclear Power Plant Costs

45

transport are larger than traditional seismic loads.
Modular construction will also shift some costs,
transferring some of the site labor costs for stickbuilding to the factory. Financing and building thefactory itself, if an existing facility is not available,
presents new supply chain risks—in fact, industry
investors may need to have multiple orders inhand before they are willing to step forward andtake the risk of developing a factory to capture
the economic benefits of modularity. In manycases, a modular approach requires sizable
up-front investments in design, procurement,
and fabrication—not only several years prior tocommissioning but also prior to start of plant
construction, which can increase financial risks
and overall financing costs. In addition, new costs
will be incurred to transport large modules tothe site. Site considerations can limit the size ofmodules that can be transported, depending on
the physical location of the site and the capacityof local roads and bridges. For these reasons,Framatome (formerly Areva) is said to be cautious
about modularization and prefers to stay with astick-built approach at this time (International
Atomic Energy Agency 2009). This decision,
however, may be influenced by the company’s EPR
design, which is large and complex and may beless compatible with modularization than otherreactor systems.
Another early study, done in 2003, looked at thepotential modularization of a number of Gen-IV
systems (Mynatt 2003) and concluded that allof them could be modularized. It examined the
MIT pebble bed design in more detail and foundthat modularization could potentially reduce
construction costs for this design between 20%
and 50%. The 2003 study concluded that thecost savings realizable from modular construction
were greatly influenced by how well the modules
fit together during final assembly, an engineering
challenge noted earlier. Companies exploring otheradvanced reactor concepts e.g. high-temperaturegas reactors (General Atomics 2011), fluoridesalt-cooled high-temperature reactors (Hong, etal. 2017), sodium-cooled fast reactors (Kwant
and Boardman 1992), and molten salt reactors(Thorcon Team 2017) have begun to consider

46

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

modularization techniques in parts of theirdesigns. (Chapter 3 discusses advanced reactor
technologies in more detail.)
As an example of the potential for advanced
manufacturing/modular assembly andconstruction to reduce advanced reactor costs, weestimate that reducing the cost and construction
time for a notional advanced reactor by 20%
would reduce the overnight cost by about$1,000/kWe. It would also reduce interest costs
during construction by one-third or approximately$600/kWe for a combined savings of $1,600/kWe,or roughly 30% of estimated overall capital cost,and a corresponding reduction of approximately$30/MWh in the LCOE.
Beyond modularization, optimized layouts for the
power conversion system, such as in the Advanced
Modern 600 MWe LWR (AM600) design
described by (Field 2017), could reduce costs by
reducing the number of components and using
more modern upgrades and planning.
Finding:

Modularization, when used judiciously innuclear plant construction and component
fabrication, could be a viable cost-reduction
strategy in advanced reactor designs. In
addition, our examination suggests that:(a) countries with high labor rates and low
productivity have stronger incentives touse modular construction in factories andshipyards to reduce labor requirements(especially for very expensive labor at theplant site), and (b) if the factories andshipyards used to produce components arelocated in countries with low labor rates
and high productivity, overall savings could
be substantial. However, for structures,
systems, and components that are lesscomplex, onsite assembly may still be theless expensive option.

Commodity Usage
Data from the best and median LWR builds fromthe 1970s (Figure 2.8) indicate that commodities(concrete, steel, piping, and electrical cables)
drive installation costs in nuclear reactors because
they are so labor intensive. This was re-affirmed
by discussions with Westinghouse regarding theAP1000. For example, a detailed examination
reveals that the fabrication of concrete forms
dominates the cost of concrete, reinforcing
steel dominates the overall cost of steel, andnon-nuclear-grade carbon steel piping dominates
the cost of piping. Concrete accounts for 25%of the total cost of 1970s-era pressurized water
reactors (PWRs), while rebar accounts for 35% of
total steel input for these plants. Nuclear concrete
comprises about half the total concrete used at anuclear power plant but it costs at least twice asmuch as non-nuclear-grade concrete (Peterson,
Zhao, and Petroski 2005) so minimizing theuse of this material will reduce costs. Nuclearquality structures also take approximately 30%
longer to build and use approximately threetimes more steel than conventional structures(Champlin 2018).
Figure 2.9 plots the amounts of concrete andsteel used in the construction of a variety of LWR
plants, advanced reactor designs, and coal plants
on a per-MWe basis. The data exhibit a wide rangeof scatter and come from a variety of sources(Peterson, Zhao, and Petroski 2005) (Roulstone2017) (Thorcon Team 2017).
More importantly, our discussions with
Westinghouse indicate that these commodity
metrics can be misleading. Careful engineering
is required on a structure-by-structure basis todetermine the optimal approach to fabricationand installation. While some structures may
use less concrete, they can be more expensive
overall because of their overall complexity,
which may create other challenges in fabricationand installation depending on the nature of
the concrete and on the amount of rebar andshear ties in the structure. For example, there issignificantly more concrete in the ABWR than in
the AP1000, but according to Westinghouse, the
ABWR was easier to construct.
Finding:

New reactor buildings and structures need
to be optimized, taking into account both theamount of material and the amount of labornecessary for fabrication and installationin an effort to minimize the overall cost ofcommodities used in plant construction as
much as possible.

Figure 2.8: Breakdown of commodity use in LWRs

Commodity Cost $266M(1986 Dollars)
1144 MWe LWRBest Experience
6%

Other

Commodity Cost $483M(1986 Dollars)
1144 MWe LWRMedian Experience
4%

Concrete (alltypes)

13%
29%
30%

24%

Steel (all types)
Piping (nuclear
and non-nuclear)

22%

14%

Ducting, Wiring,
Cables38%

20%

Chapter 2: Nuclear Power Plant Costs

47

Figure 2.9: Comparison of commodity use in a variety of nuclear reactors and coal plants
450

Concrete Volume m*3/MWe
Metal MT/MWe

400
350
300
250
200
150
100
50
0

1970s era
LWR

1980
estimatefor LWR

ABWR

ESBWR

EPR

AP-1000

NuScaleAdvanced Concrete
A variety of advanced concrete products andrelated construction techniques, including
automated pouring, functionalized concrete,prefabricated concrete, steel plate composites,
ultra-high performance concrete, high-strength
reinforcing steel, and geopolymer concrete havebeen introduced that have the potential to reduce
capital costs for new nuclear plants:• Automated pouring, in which the concrete ispoured by a machine rather than by hand, canreduce formwork and labor (which drives costs
in LWRs today), and improve standardization.
• Functionalized concrete uses cheap additives
such as fly ash to improve specific propertiesof the concrete. This could, for example, reduce
the thickness of the concrete walls needed in an
aggressive environment such as a nuclear plant.
• Prefabricated concrete is pre-poured at an
offsite facility and then delivered to the site.
This offers several benefits, including mass
production, much faster installation, and theability to check the quality of pieces before
installation. Prefabricated concrete does,
however, involve higher transportation costs.
• Steel plate composites (SPCs) consist of
concrete sandwiched between two steel
plates connected by tie bars. SPC forms can
include any necessary penetrations and piping

48

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Sizewell B N4 (French GT-MHR
PWR)(HTGR)

Large SFR

FHR

ThorCon
(MSR)

Coal

runs. Structural credit for the steel–concrete
combination can reduce the amount of rebar
required, and because the steel plate structure
can be self-supporting, reinforced concrete
sections can be modularized and prefabricatedoff-site and subsequently placed and welded onsite—potentially cutting the installation time inhalf (Omoto 2002). This technology achieved
nuclear certification in the United States in2015 (Varma 2017).
• Ultra-high performance concrete (UHPC) isa concrete that achieves very high strengthwith dispersed steel fibers or admixtures ofsilica fume and fly ash (Li, et al. 2017). It is
designed to replace reinforced concrete. The
largest source of commercially available UHPCis Ductal®; similar products include Cor-Tuf(Williams 2009) and CEMTEC (Rossi 2005).
Because it costs more than regular concrete,
UHPC would only be used in rebar-dense areas
or as a liner.
• High-strength steel in reinforced concrete isused to reduce the amount of rebar needed
and thus reduce the time and cost associatedwith rebar placement. It also reduces problems
associated with the concrete voiding that is
typical in high-density rebar cages (this was
experienced, for example, in the EPR design)(National Earthquake Hazards Reduction
Program Consultants Joint Venture 2014).

• Geopolymer concrete is similar to UHPC inthat it incorporates dispersed fibers, but it is
not expected to be much more expensive thanregular reinforced concrete.
Ideally these advanced concrete technologies
would not be independent. An example of a
streamlined process might involve pre-fabricating
a UHPC or SPC shell in a factory, and thenshipping the shell to the site. On arrival, theseshells are pre-stressed and joined together (inthe case of UHPC) and filled with functionalized
concrete by an automated pourer. Similarly,
modular floor design and installation can be usedin conjunction with slip forming for the walls. Afterthe outer vertical walls of a building are installedby slip forming, the modular floors can be installed
through the open top of the building by means ofa heavy lift crane. Modular floors consist of steel
modules that include rebar but no concrete; themodules are placed on supports embedded in theconcrete walls during the slip-forming process.
Modular floors are designed to be transported
from the assembly shop, installed by cranes,
welded to supports embedded in the walls, andthen filled with concrete.
A project in the United Kingdom (Locke 2016)
has shown that 70% of the civil engineering
activities in a nuclear reactor new build canbe re-engineered to take place in a modular
fashion in a factory. Furthermore, using concrete
structures that are designed for manufacturability
and assembly and employing advanced concrete
manufacturing techniques can reduce theconstruction time for these components by
80%. Most of these options are or will soon
be commercially available. Some will requireapproval by the nuclear regulatory authority. A
key step toward such approval is incorporating
innovative concrete solutions into relevant codesand standards for use in nuclear systems (e.g.
American Concrete Institute).

Finding:

Civil engineering activities in support of newreactor construction can be performed ina modular fashion by employing structuresthat are designed to be manufactured
and assembled using advanced concrete
techniques when such an approach is lessexpensive than conventional ‘stick building.’

Advanced Siting Options: Standardizationand Multi-Unit Sites
As demonstrated by the KEPCO Engineering andConstruction Company (both in South Korea andthe United Arab Emirates), having a complete
standardized design that is built repeatedly,at many different sites, is key to successful
nuclear builds because it allows a construction
team to learn with each subsequent unit. Even
better is building multiple units at the same site.
This approach was also demonstrated in theconstruction of Japan’s boiling water reactors(BWRs). Standardization results in an economy
of replication, which should reduce costs.
Similar results have also been confirmed by
Berthélemy and Escobar-Rangel (2013). They
found that standardization in the French fleet
played an important role in cost reduction because
it enabled learning by doing. Conversely, theseresearchers concluded that a diversity of nuclear
reactor models can lead to delays because of
supply chain constraints or increased workload
for regulators. Vertical integration of the architectengineering firm and the utility can also reducecost. More interestingly, Berthélemy and EscobarRangel also found that incremental innovation, as
has occurred with LWRs, increases the complexityof nuclear reactors. This result is in direct contrast
to the pattern in other energy industries where
technical progress has typically contributed tocost reductions. Berthélemy and Escobar-Rangel
explain this trend by noting the importance ofsafety regulation in the nuclear power sector,
which improves safety performance but at theexpense of increased construction costs. In
particular, they note that the U.S. nuclear industry

Chapter 2: Nuclear Power Plant Costs

49

was hampered in efforts to standardize plantdesigns by the myriad new safety regulations thatwere introduced following the accident at Three
Mile Island Unit 2. Nonetheless, these authors
posit that radical technology changes—like thoseincorporated in Generation-IV technologies (seeChapter 3)—might reduce cost.

Advanced Siting Options: Embedment andSeismic Isolation
Nuclear power plants, unlike natural gas, coal,and chemical plants, are required by regulators toaddress a set of natural and man-made external
events (e.g., earthquake, tornado, flood, airplanecrash, fire) and malicious acts as part of the designbasis. Thus, plant buildings and structures, andplant safety systems are hardened to withstandthese events and maintain their safety function.
(This hardening imparts a high degree of resilience
to nuclear systems.) Because safety requirements
can be major cost drivers, new technology options
for meeting these requirements can help reduce
plant costs.
Most of the advanced reactor designs being
proposed today would be located in a below-grade
embedment, both because they are smaller thanconventional LWRs and because embedment
may be a more economical way to address certain
natural phenomena and design basis threats(Figure 2.10). A recent HTGR embedment study(General Atomics 2008) discusses the tradeoffs
of embedment and concludes that feasibility andeconomic potential are dependent on the plantsite and water table. The depth of the embedment
is determined by the size of plant components(vessel and steam generator) and in some casesby the need for natural circulation—that is, someconcepts may require a minimum gravity head.
The technology to efficiently excavate a large,
deep hole exists for a variety of soil types. The
mining industry uses vertical shaft machines tocreate ventilation shafts. Two companies currently
offer this technology: Herrenknecht can produce
holes with depths of up to 5 meters per working
shift to a maximum diameter of approximately 16
meters and a maximum depth of about 80 meters(Kiewit 2018) (Herrenknect AG 2018).

50

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Figure 2.10: Cutaway schematic of reactor embedment
Roof
Reactor Cavity Cooling System
Inlet Exhaust Structure

Grade

Fuel Handling
Floor
Fuel Handling
Equipment

Operating Floor
Elevation 0’-6”
Eleva

Steam Generator
Vessel

tio

n-

28

’

Reactor
Vessel

Ele

va

tio

n-

14

4’

For modular HTGRs that use TRISO-coatedparticle fuel, a functional containment approachhas been adopted whereby the fuel is the major
radionuclide retention barrier, not traditional
containment structures. (More detail on
TRISO-coated fuel as used in HTGRs is provided
in Chapter 3.) In such reactors, locating theplant below grade could obviate the need for astrong above-ground containment structure. In
the 1990s, a team estimated cost savings for aconventional confinement building compared toa traditional high-pressure containment building
as part of a broad cost-reduction strategy for
HTGR technology (Gas Cooled Reactor
Associates 1990). The team found savings of up
to $93 million (in 1990 dollars) for a plantcontaining four 450 MWth reactors; these savings
corresponded to an overnight cost savings of$134/kWe (again, in 1990 dollars) or $250/kWe
today. This cost savings does not consider any
additional hardening required to meet designbasis threats such as large airplane crashes(airplane crashes were not considered in 1990)
nor does it include the cost of seismic isolation(discussed next).

Adaptations to accommodate seismic hazards
are a large fraction of the site-specific cost of a
nuclear plant. In fact, costs related to this typeof hazard have increased in the United Statesby a factor of two since the Three Mile Island
accident (Champlin 2018). Seismic isolation offersa means to minimize the impact of site-specificfeatures on the design. By digging out a second
basemat beneath the main plant, isolators can beinstalled below the traditional basemat to act as
shock absorbers for plant buildings. Horizontal
acceleration from an earthquake is effectively
dampened by the isolation system, althoughvertical displacements must still be considered.
Seismic isolation will reduce the need for extensive
plant modifications in locations that are highly
seismically active, including reducing the needfor hardening measures (e.g., snubbers, thicknessof concrete structures). A schematic is shown in
Figure 2.11. Seismic isolation technology increases
the number of potential sites for a nuclear power
plant and, more importantly, allows for muchgreater standardization and less site-dependent
designs. This could play a large part in reducing
site-adaptation design costs. The technology
is technically ready and has already been
implemented by other industries and in nuclear
facilities overseas. Three major nuclear systems
that use (or will use) seismic isolation include
the Koberg PWR in South Africa, the ITER facility
in southern France, and the new Jules Horowitz
irradiation test reactor in southern France. U.S.
regulators have recently drafted guidance on
seismic isolation (Kammerer, Whittaker, andConstantinou 2013) but have not yet approved
the use of this technology in nuclear power plants
as a way to improve seismic safety. According
to a recent study by (Bolisetti, et al. 2016), theisolators provide an overall net cost reduction
when the peak ground acceleration exceeds
0.2 g—which notably includes every nuclear
plant site in the United States (‘g’ is a unit ofmeasure for acceleration due to gravity). Basedon other non-reactor nuclear facilities, overall
seismic isolation could reduce overnight costs
by approximately 5%, not including the benefits
from standardization. More recent work has
focused on developing solutions to reduce bothhorizontal and vertical displacements during aseismic event using phononic crystals to dampen
acoustic waves. Recent work (Yan, Cheng, etal. 2015) (Xiang, et al. 2012) (Yan, Laskar, et al.
2016) is extremely promising but has not yet been
incorporated into relevant regulatory standards.

Advanced Siting Options: Offshore Platforms
Offshore platform designs, in which the reactor is
integrated in an offshore rig, offer an alternative toembedment for coastal sites since site preparationis reduced to installing attachment and/or mooring
systems (Figure 2.12). Also, a concrete shield may
not be necessary in these designs, since the NSSS
can be situated below the water line and behind
multiple thick steel hulls. Two general designs havebeen proposed: floating platforms (Buongiorno,
et al. 2016) (Ford, Abdulla, and Granger Morgan
2017) (D.W. Richardson 2014) (Ganesan 2016)

Figure 2.11: Examples of seismic isolation
Elastomericisolation bearing

Elastomericisolation bearing

Fluid viscousenergy dissipator

Flexible pipe
connection

16-50055-02

16-50055-01

Chapter 2: Nuclear Power Plant Costs

51

Figure 2.12: Example of offshore floating power plantand standing platforms (Ashworth 1974) (Lee,et al. 2013). Floating platforms eliminate seismic
concerns, but introduce other considerations
associated with the potential for platform sinking
and the effects of platform motion on reactor
behavior, especially with respect to safety systems
that rely on natural circulation. Standing platforms
eliminate such issues but are limited to relatively
shallow water sites. In either case, other external
hazards (storms, tornadoes, marine collisions)as well as the in-leakage of water need to beconsidered. Offshore designs can reduce siting
difficulties by making it possible to use sites thatare uninhabited and do not compete with otherland uses. They would also allow for rapid
decommissioning via removal of the platform at
the end of plant life. Ocean delivery, in which theentire plant is constructed in a shipyard anddelivered in one piece to the site, would mean
moving from a sequential, low-productivity
construction process to a parallel, highproductivity manufacturing process—withpotentially large impacts on the cost and schedule
for plant delivery. Substantial cost reductions
versus an nth-of-a-kind land-based PWR could be
realized in the following categories: elimination ofsite preparation costs (approximately 10% of plantcost), direct labor (20% reduction in expected
cost on first plant compared to a conventionallybuilt plant, and greater reductions on subsequent52

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

plants), materials (concrete eliminated along withformwork, rebar, inspection, etc.), construction
supervision (approximately 50% reduction due towork practices in the shipyard), and fieldengineering (near complete elimination due tocompleted engineering prior to fabrication).
However, operating costs are expected to behigher for offshore plants because of higher labor
rates for offshore personnel and somewhat higher
electricity transmission costs with underwater
cables. Lastly, we note that the idea of a ‘shipyard
made’ plant can also be applied to a coastal sitethat is not offshore—in that case, the plant is built
in a shipyard, is then towed to an artificial wet
dock at the site, the dock is drained, the plant
operates for its lifetime, and at the end of its
lifetime the dock is flooded and the plant is towed
away for decommissioning.
Finding:Standardization (especially at multi-unit
sites), embedment below grade orunderground (or, alternatively, offshore
siting), and seismic isolation can reduce
construction costs and improve safety
and security.

Coatings and Nano-Textured Surfaces
Hydrophilic or hydrophobic coatings are a surface
treatment that can be applied to various power
cycle components to affect how the coolant
interacts with them. The result is improved heattransfer on hydrophobic condenser tubes due tothe elimination of the condensation-inhibiting
liquid films that typically form, or enhanced
boiling in hydrophilic steam generators and BWR
cores due to a reduction of insulating steam (orLeidenfrost) layers. Both of these effects improve
the thermodynamic efficiency of the cycle byallowing the affected heat exchanger to operate
at lower temperature differences for the same
performance, which in turn translates to higher
pressure drops across (and thus more work outof) the turbine. Additionally, these coatings can
reduce the buildup of harmful deposits, suchas Chalk River Unidentified Deposits (CRUD),
and prevent corrosion in reactor cores; thus, thecoatings are also characterized as ‘CRUD-phobic.’Heat transfer coatings can improve efficiency forlittle additional cost. For example, hydrophobic
coatings are expected to cost less than $1 persquare meter to implement, can be retrofitted
on old condensers, and are technically readynow (Varanasi 2017). Our analysis (Champlin
2018) of the effects of introducing hydrophobicity
to a PWR condenser shows a 1.3% (additive)
increase in plant efficiency, for a reduction of
approximately 1% in outlet steam quality and anegligible increase in air in-leakage. The durabilityof these coatings, however, has yet to be proven.
For example, debris problems could arise if thecoating is susceptible to flaking after extended
use. A coating should not need to be replaced
more often than the component it is applied towould otherwise need maintenance. Achieving
this level of durability has been an issue in thepast, but companies such as DropWise and NEICorp’s Nanomyte (NEI Corporation 2016) claim
to offer hydrophobic coatings that are technicallyready now.
The cost impact is similar for hydrophilic and
CRUD-phobic coatings, which offer a 0.6%
increase in efficiency and savings of approximately$1–$3 million per year in fuel costs (Karoutas 2017).

However, durability remains a key issue because
these coatings have not yet been found to becapable of performing under industrial conditions
for extended periods of time. It is hoped that thesetypes of coatings will be ready for use in nuclear
power plants by 2030.

Energy Storage
The use of energy storage technologies is apotential mechanism for enhancing revenues
from baseload nuclear power plants because it
would allow plant operators to store energy when
the price of electricity is low, and then sell thatenergy when demand is high. (Energy storage
may also be useful for other types of generation
technologies, notably intermittent renewables,
but perhaps at a different scale.) In essence
this would open up new peaking markets fornuclear beyond traditional baseload operation.
We examined a broad range of energy storage
technologies (Champlin 2018) including electricalstorage (capacitors and electromagnetic devices),mechanical storage (pumped hydro, compressed
air, and flywheels), batteries (including a rangeof static and flow types), and thermal storage(of both sensible heat and latent heat). A plot ofprojected storage costs at the scale necessary
for integration with a nuclear reactor is shown in
Figure 2.13. These results show that, in general,
thermal and some mechanical storage is cheaper
than electrical storage (Forsberg, C. 2017).
Additional details are provided in Appendix J.
Because storing heat from a nuclear reactor isinherently lower cost and has a higher overallround-trip efficiency than storing electricity,
we examined several thermal or heat storage
technologies in more detail, including steam
accumulators, sensible heat fluid systems,
cryogenic air systems, packed bed thermalenergy storage, hot rock storage, and geologic
storage systems.
With these options, the reactor operates at fullpower and a large fraction of the power conversion
fluid is diverted from the turbine to the heatstorage system at times when electricity prices
are low. The remainder of the steam goes to theturbine to produce a minimum level of electricity.

Chapter 2: Nuclear Power Plant Costs

53

Figure 2.13: Added cost ($/MWhe) of different energy storage options in nuclear power plant applications
Sensible Heat
Compressed Air
Latent Heat
Pumped Hydro
Iron Air
Lead Acid
Polysulphide Br
Zinc Air
Vanadium Redox
Solid Oxide
Zinc Bromine
Nickel Zinc
Na-Ni Chloride
Alkaline
Sodium Sulphur
Nickel Metal Hydride
Molten Carbonate
Lithium Ion
Flywheel
Nickel Cadmium

0

2

4

6

8

10

12

14

16

18

Added Plant LCOE [$/MWh]
The color of the bars signifies the type of storage: green is mechanical, orange is thermal, and blue is electrical.

In this case, because the turbine always remains
in operation, it can be rapidly returned to 100%
power output as necessary. Integration options
vary for these technologies. In some cases, theenergy is converted directly from the heat storage
system into electricity using power conversion
equipment similar to that used by a nuclear
reactor. In nuclear systems that have an oversized
turbine (a new build or modification of an existing
reactor), the energy can be returned to the turbine
inlet to make electricity. To ensure that generation
is available to meet peak demand in situations
where the stored heat might be depleted, boilers
fueled by natural gas, oil, biofuels, or ultimatelyhydrogen can be added as a backup to provide
steam that would otherwise come from storage.
This may be an economic option for providing
extra capacity to meet demand for assured
electricity production and for generating additional
revenue in the form of capacity payments(Forsberg and Varrin 2018). As with any hybrid
energy system, an economic tradeoff exists
between investing in storage technology versus
the revenue that can be generated.

54

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

The first three technologies we considered (steam
accumulators, sensible heat fluid systems, andcryogenic air systems) have been demonstrated at
the 1–100 MWh scale. Steam accumulators wereused as early as the 1920s for variable electricity
production and are available today. Sensible heatfluid systems have been used with solar thermal
power systems using oil as the heat transfer fluid.
Cryogenic air systems can be coupled to any heatsource and a pilot plant is currently in operation in
the United Kingdom. The other technologies are
longer-term options. Most of them can provide
for daily up to weekly variations in electricity
demand. Geologic storage systems, which are
the least mature technology, could provide forseasonal storage and could be used to provide astrategic heat reserve though such systems could
be deployed only in specific local geologies.
The overall economics of many potential energy
storage systems have not been extensively studied
yet. Furthermore, each storage technology has
different characteristics such as rate of charging,round-trip efficiency, rate of discharge, cost of
storage ($/MWh) and cost of associated energy
conversion ($/MWe). As a consequence, thepreferred option will depend on the electricity

market. In a grid with large concentrated solar
power capacity and the need for daily energy
storage, the preferred heat storage system will
likely be different than in a system with excess
wind capacity and multi-day cycles of low- andhigh-priced electricity. Several of the technologies(e.g., hot rock and geological) may be able toparticipate in capacity markets since they can
produce electricity when needed. The ability ofthe other technologies to participate in capacity
markets will depend on how these markets aredefined. This is in contrast to many other storage
technologies where incremental storage costs
are too large for participation in capacity markets
to be viable. Today, natural gas generation is thepreferred option for dealing with temporal changes
in electric load—largely because of the low costof natural gas. However, with a carbon constraint,
thermal energy storage systems could offer a costeffective, carbon-free alternative.
Our assessment of cost-reduction opportunities
and technologies suggests that the overnight
cost of nuclear reactors in the United States
could be reduced by 25% to 30% (modular
construction: 15%–20%; embedment: 5%; seismic
isolation: 5%) from the nominal benchmark
value of approximately $5,000/kWe (in the2009 update to MIT’s original Future of Nuclear
study) to $3,500–$3,750/kWe. A 25% reduction
from a nominal overnight cost of $5,500/kWe
provided the basis for the ‘Low Cost Nuclear’modeling scenarios discussed in Chapter 1. As
noted previously, overnight costs for advanced
nuclear systems built in China or South Korea,
where labor rates are lower than in the UnitedStates and construction productivity is higher,
could be significantly lower. The crosscutting
technological innovations discussed in this chapter
are applicable to all nuclear reactor concepts,
including evolutionary LWRs, small modular
reactors, and Generation-IV reactors.

Chapter 2: Nuclear Power Plant Costs

55

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Chapter 3

Advanced Reactor Technology Evaluation
This chapter reviews the range of advanced reactor technologies, currently proposedor under development, that could be deployed as part of a new wave of nuclear energy
investments this century. These systems include small modular light water reactors
and Generation-IV reactors that use non-water coolants. These advanced systems haveattributes that allow for missions beyond electricity generation and many have desirable
safety characteristics. We also estimate costs for these technologies. Each is at a different
level of technical maturity and as such has a number of key technology development
challenges to overcome prior to being ready for commercial deployment. We discuss
the overall timeframe needed to reach commercialization for different reactor concepts
based on their current technical maturity, prior experience with the specific technology
involved, and historical experience related to the commercialization of nuclear systems
more broadly. Finally, we draw on our findings to propose a new deployment strategy forthe least mature of the advanced nuclear energy systems.

3.1 REACTOR TECHNOLOGIESAdvanced reactor technologies can becharacterized by the coolant they use and by
their neutron spectrum as shown in Table 3.1.
The coolant transfers heat produced in the reactor
to the electrical generator or other systems
that utilize the heat. Many key reactor features(e.g., operating temperature, pressure, materials)
are designed to assure compatibility with thecoolant. The neutron spectrum refers to the kinetic
energy of the neutrons in the reactor. Fission
neutrons are born fast and can be slowed down
by collisions with a moderator. Fast reactors do
not have a moderator to slow down the energyof the neutrons; thus, fission reactions occur onlyat high neutron energies. Thermal reactors use amoderator to slow down the neutrons and mostof the fission reactions occur at low energy. Most
existing reactors used to generate electricity arelight water reactors (LWRs), which are cooled withwater and operate with a thermal neutron spectrum.
Fusion technology is summarized in a Sidebar 3.1,
but we do not cover this technology in detail.
This chapter begins by providing a brief
description of different types of advanced reactors,
which can range in power output from micro-size(less than 10 megawatts of electrical generating
capacity or MWe), to small modular designs (upto 300 MWe per reactor module depending on the

Table 3.1: Characterization of advanced nuclear reactor systems by coolant and neutron spectrum
Coolant

Thermal Neutron Spectrum

Fast Neutron Spectrum

Water

Small Modular Reactor (SMR)

HeliumHigh Temperature Gas-Cooled Reactor (HTGR)
and Very High Temperature Reactor (VHTR)

Gas-Cooled Fast Reactor (GFR)

Liquid Metal—

Sodium Fast Reactor (SFR), Lead-Cooled Fast Reactor(LFR)

Molten Salt

Fluoride-Cooled High Temperature Reactor (FHR),
Molten Salt Reactor–Fluoride (MSR–fluoride)

Molten Salt Reactor–Chloride (MSR–chloride)

Chapter 3: Advanced Reactor Technology Evaluation59

design), all the way up to larger units (as much as
1,200 MWe). Information about each technology
can be found in the literature (Generation IV
International Forum 2002) (Pioro 2016),(International Atomic Energy Agency 2013),
including details about its scientific status (Abramand Ion 2008) (Locatelli, Mancini, and Todeschini2013) (Futterer, et al. 2014) and engineering
challenges (Allen, Sridharan, et al. 2008) (Allen,
Busby, et al. 2010). (Note that for purposes of thischapter, references to ‘modular’ designs indicatethat multiple reactor modules can be put on thesame site to obtain the overall generating capacity
desired by the customer. In Chapter 2, which
focuses on cost, the concept of modularization is
discussed in relation to the opportunity to fabricate
nuclear power plant components in a factory as
a way to reduce costs and simplify construction.
This type of modularization should be applicable
to nuclear power systems of all sizes.)

Small Modular Light Water Reactor (SMR)‘Small modular light water reactor’ is a term thathas been coined for small LWRs with a high degreeof passive safety. As noted earlier, SMR designs
encompass plants with an electrical generating
capacity of less than 300 MWe for an individual
module. The SMR design being offered by NuScale
Power (2018) is the most mature concept in thistechnology space. It consists of multiple (up to adozen) 50-MWe reactors that use a common waterpool as their ultimate heat sink. The NuScale
design and similar concepts leverage the large
operating experience of the current LWR fleet withsmaller and simpler configurations. This allows
designers to eliminate active safety systems andrely on passive safety features. In these types ofdesigns, minimal-to-no electrical power is required
to actuate safety systems and provide long-termcore cooling in the case of an accident.

Modular High Temperature Gas-Cooled
Reactor (modular HTGR)This term describes a graphite-moderated
helium-cooled thermal reactor (Kadak 2016).
The reactor’s low power density (i.e., power per
unit volume of the reactor core), coupled with60

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDa high heat capacity graphite moderator androbust TRISO-coated particle fuel (Figure 3.1a)
provides a high degree of inherent safety. TRISOcoated particles are small poppy-seed-sizedparticles containing a core of ceramic uranium(oxide, carbide, or a mixture) encapsulated inlayers of dense carbon and silicon carbide. These
particles provide containment of the radioactive
byproducts of fission and their robustness
minimizes radioactive releases to the environment.
Two design variants exist: (a) a prismatic graphite
moderator block that contains graphite cylinders
laden with the TRISO particles and (b) a pebble
bed made of cue-ball-sized graphite pebbles,
also containing TRISO fuel particles. The pebbles
slowly circulate through the core allowing foron-line refueling. The reactor coolant outlet
temperature is generally between 700°C and
850°C for most of these designs. A variant of
this design features higher outlet temperatures(900°C–950°C) and is called the ‘very hightemperature reactor’ (VHTR). The VHTR concept
requires additional technology development; there
is interest in this design because the higher outlet
temperature may be important for the process
heat applications that are discussed later in thischapter. Companies that are currently working on
HTGR technology include Framatome, X-energy,
U-Battery, and STARCORE.

Gas-Cooled Fast Reactor (GFR)
The GFR is a high-power-density fast reactor
cooled by high-pressure helium. Conceptual
designs envision a core that contains ceramic(as opposed to metallic) fuel and structures toaccommodate the high temperatures. Uraniummono-carbide fuels are usually considered foruse in this design because they meet the highfissile density requirements for a fast reactor(fissile density refers to the concentration of
uranium atoms per unit volume of fuel). Outlet
temperatures for most proposed designs of thistype would be approximately 850°C. The GFR
concept has been considered in the past by
France (Dumaz, et al. 2007) and more recently
by General Atomics (Choi and Schleicher 2017)
but has never been built.

Figure 3.1: Fuels for advanced reactors(a) TRISO-coated particle fuel is used in high temperature gas-cooled reactors (upper panel); (b) metallic fuelis used in many sodium fast reactor designs (lower panel). Both of these fuel systems have higher burnups than
LWR fuel rods. They also offer greater compatibility between fuel, cladding, and coolant, which results in superior
accident tolerance. (Burnup—also known as fuel utilization—is a measure of how much energy is extracted from theprimary nuclear fuel source.)

Chapter 3: Advanced Reactor Technology Evaluation

61

Sodium Fast Reactor (SFR)
As its name suggests, this type of fast reactor iscooled by liquid sodium. It operates at very highpower density given the absence of a moderator
and the excellent heat removal capability ofthe sodium coolant. Most of the designs underconsideration today are small SFRs that haveinherent and passive safety features that may
not be viable in larger sodium systems. The fuelof choice in the United States is a metallic alloyof uranium and zirconium clad in steel, whileinternational programs (Russia, France, Japan)
utilize oxide fuels. Metal alloy fuel, shown in
Figure 3.1b, has low stored thermal energy and thecore expands under off-normal high-temperature
conditions, providing a negative nuclear reactivity
feedback to limit any power increase. ManySFR concepts, like GE’s PRISM design (Triplettand Loewen 2012), recycle their fuel and thus
operate on a fuel cycle in which the fuel contains
both uranium and plutonium to keep the core
very compact. Larger cores that do not containrecycled plutonium and achieve very long-lived
fuel cycles (that is, the fuel can be used for
decades before it needs to be changed) are
under development (for example, by Terrapower(Ahlfeld 2011)); these designs, however, require
advances in fuel and materials technology to meet
performance objectives. Outlet temperatures
for SFRs are generally between 500°C and
600°C due to structural material limitations.
Advanced SFRs are under consideration that use
different structural materials or different power
conversion technologies to further improveoverall performance. These concepts have thepotential to reduce cost but require additional
technology development.

Lead-Cooled Fast Reactor (LFR)
The LFR is an alternative fast reactor concept thatuses liquid lead for cooling instead of sodium. It
derives from Russian submarine technology andexperience. Two different fuel forms are usuallyconsidered with this system. Some proposed
designs utilize uranium dioxide (UO2) fuel, which
has been used in older sodium fast reactors.
Other designs propose to use uranium nitride(UN) fuel because it offers high fissile density

62

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

compared to oxide but this fuel technology is not
yet mature and thus would require significant
development. Some concepts, leveraging
Russian submarine experience, involve low outlet
temperatures between 300°C and 500°C, whileothers propose to operate at higher temperaturesof 500°C–600°C like sodium systems. Even
higher temperatures are a goal for some designs
but before operation at outlet temperatures of
700°C–750°C is possible, further technology
development is needed to address issues related
to the corrosion and erosion of metallic structuresin the core by the lead coolant. In the UnitedStates, Westinghouse has been exploring thisadvanced reactor concept (Ferroni 2017).

Fluoride-Cooled High Temperature Reactor(FHR)
The FHR is a high temperature reactor that uses
a fluoride-based salt (such as FLiBe, a mixtureof lithium fluoride and beryllium fluoride) as
the coolant instead of helium (Forsberg 2014).
The reactor is designed to operate at four to
ten times the power density of an HTGR, with
TRISO-particle fuel technology. The use of afluoride-based molten salt, with its superior heattransfer characteristics compared to helium, resultsin lower fuel temperatures. Both prismatic andpebble designs have been considered; the pebble
design is currently more advanced. The outlet
temperature of the molten salt coolant in proposed
designs of this type is approximately 700°C,
however, as discussed later, there are significant
material challenges associated with long-term
operation above 650°C. Kairos, a recent startup,
is developing the pebble bed version of the FHR.

Molten Salt-Fueled Reactor (MSR)
The MSR class of reactors uses a molten salt as
both coolant and fuel because the fuel is dissolvedin the salt. There are both thermal and fastvariants of this design. The thermal systems use
a fluoride salt (i.e., salt that contains the element
fluorine) with graphite or another material as amoderator to slow the fission neutrons down tothermal energies. The fast reactor variant uses
chloride salts (i.e., salt that contains the element
chlorine). Power densities are generally as high as

Figure 3.2: Temperature and displacement damage windows for advanced reactor concepts

Adapted from Zinkle and Was (2013).

those of LWRs for thermal systems and as high as
sodium fast reactors for fast systems. Proposed
outlet temperatures from the reactor core are in
the range of 700°C–850°C, however as discussed
later there are significant material challenges
associated with long-term operation above 650°C.
Higher temperatures up to 1,000°C are proposed
but would only be achievable if concerns aboutmaterial corrosion by the salt coolant, along withconcerns about radiation damage and material
strength are resolved. Fluoride and chloride salts
have high melting points and thus the reactor inlet
coolant temperature for these systems must be
above 500°C to prevent freezing during normal
operation. A variety of conceptual designs havebeen proposed (World Nuclear Association
2017), all of which require significant technology
development. Companies that are currently
pursuing this technology include Southern
Company/Terrapower in the United States,
Terrestrial Energy in Canada, Moltex in the United
Kingdom, and ThorCon, a U.S.-based company
that is planning to deploy in Indonesia.
Nuclear reactor systems can be compared using
key parameters—such as operating temperatureand neutron damage to important core structures,such as the fuel cladding—that limit operational

conditions. A key metric for the level of neutron
damage is the neutron-induced displacementof atoms from their original positions in thematerial lattice, which is measured in termsof displacements per atom (dpa). The levelof damage is a function of the material being
tested, the damage probability, the neutron
spectrum, the neutron flux, and the irradiation
time. High levels of displacement damage (highdpa) challenge a material’s ability to perform its
function in the neutron environment. The level ofdisplacement damage can determine the lifetimeof the component, which may have to be replaced
once that level of damage is exceeded. New
radiation-resistant materials may be required toaccommodate damage levels in excess of 200 dpa.
Figure 3.2 shows neutron damage/temperature
operating windows for LWRs (Generations II–III
and SMRs) and for different Generation-IV
concepts. The damage levels shown in Figure 3.2
span the values expected for both fuel cladding
and structural materials in the reactor core; forshielded load-bearing components, the damagelevels will be much lower. LWRs (including SMRs)
operate at low outlet temperatures (approximately
300°C) and low damage levels (i.e., less than
5–60 dpa). (Note that, with life extension, 80 dpa

Chapter 3: Advanced Reactor Technology Evaluation

63

Sidebar 3.1: What About Fusion?
Fusion is a nuclear technology that harnesses fusion
reactions between atoms, instead of fission reactions—as inconventional nuclear power reactors—wherein atoms are split
apart, to generate useful energy. If fusion could be practically
implemented, it would offer a low-carbon energy sourcewith many positive safety and environmental attributes.
However, uncertainty in the science of net-energy-producing
fusion plasmas, and the massive size and complexity of thedevices required to produce them, continue to make fusion
the energy source that is perpetually many decades into the
future. This situation is perhaps best exemplified by ITER
(for ‘International Thermonuclear Experimental Reactor’),an ambitious international fusion research and engineering
demonstration project in which some 35 nations are involved.
ITER is now constructing a large tokamak reactor in southern
France with the aim of demonstrating a net-positive fusionenergy process by 2035. The reactor is expected to take20 years and cost approximately $20 billion to construct.
This development pathway, while scientifically sound andjustified, is taking much longer and proving much more
expensive than originally anticipated, pushing hopes forcommercializing fusion power to beyond 2050. Clearly, fusionenergy is a technology in need of innovation, especially in theengineering required to deliver it as a practical energy source.
Recent advances in materials enable an alternative development
path for fusion energy. For example, the availability of hightemperature superconductors (HTS) could change the designof a tokamak in key ways. Electromagnets using HTS can produce
magnetic fields with double the field strength of previous
superconductor technology, resulting in an order-of-magnitude
increase in the fusion power density and a correspondingly large
volume reduction of the fusion device. In addition, HTS magnets
have a much wider operating space, allowing for design featuresthat can increase the modularity of the fusion device and achieve
more effective heat removal, thereby overcoming limitationsin the traditional configuration.
These advances open a potential pathway to improving the costcompetitiveness of fusion energy systems. However, significant
technology development is still required in several areas tomake fusion a reality (e.g., tritium processing and breeding,blanket and divertor technology). While it is too early at thisjuncture to evaluate precisely how future technology innovation
will affect the overall trajectory for developing, demonstrating,and eventually commercializing fusion energy, the developmentof large-bore HTS magnets will clearly play a large role.
This development is now underway.

64

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDis being reached in some existing LWRs.) VHTR/HTGRs and FHRs also operate at low damage levels(i.e., less than 5–30 dpa) but high temperatures(600°C–950°C). Components in fast neutron
systems (such as the SFR, LFR, GFR, and fastspectrum MSR) are subjected to much higher
damage levels (50–200 dpa) and operate over arange of temperatures (400°C–1,000°C) dependingon the design concept. The figure includes the
Terrapower Traveling Wave Reactor (TWR), an
SFR concept that proposes to reach damage levels
up to 600 dpa because of its long-lived core.

Technical Characteristics
The different technical characteristics ofadvanced reactor systems shown in Table 3.2(e.g., higher outlet temperature, different neutron
spectra, different safety characteristics) havesome potentially positive impacts on operationand economics. They also influence potential
applications for the reactor as discussed later.
Except LWR-based SMRs, all of these systems
have outlet temperatures higher than conventional
LWRs. As a result, the overall thermal efficiency
is higher (generally between 40% and 50%).
This would tend to reduce the cost of electricity
relative to the traditional 33%–35% efficiency of
LWRs, assuming comparable capacity factors.
This also reduces associated water use forwaste heat rejection by up to 50% on a per-unitelectricity-generated basis, which can be evenmore important in more arid locales. Water use
could be eliminated altogether if dry cooling wereadopted (at the cost of a reduction in overall
thermal efficiency).
Except for SMRs, most fuels proposed foradvanced reactor concepts require uranium
enrichments above 5%, usually between 10%
and 20%. The added cost of this enrichment
must be weighed against the significantly higher
fuel burnups attained in these systems: typicalburnups are two-to-three times higher thanconventional LWR fuels. New fuel forms will alsoentail higher fuel fabrication costs in the earlystages of deployment.

Table 3.2: Select technical characteristics of advanced reactors
Technology

Core Outlet
Temperature

Efficiency

NuScale SMR

310°C

32%

Rolls Royce SMR

327°C

≈35%

Modular HTGR

750°C–950°C
depending on
design and mission

Fuel Burnupa
5–6 atom% using shorter
length LWR fuel rods
5.5–6 atom% using shorter
length LWR fuel rods
10%–20 atom% using
TRISO fuel corresponding
to enrichments of 10 to 20%

SFR like PRISM
or Terrapower

500°C–600°C

LFR

300°C–750°C
depending on
design and mission

43.5%–50%
depending on outlet
temperature
43%–50% depending
on design of power
conversion system≈35%–40% (the useof an intermediate
loop reduces theoverall efficiency)≈34%–45%
depending on thedesign

FHR

700°C

≈42%

Similar to HTGR. Uses
TRISO fuel.

≈40%–42%High fissile burnup is
proposed because fuel isdissolved in coolant. Burnup
is limited by reactivity
considerations and theefficacy of on-line fission
product removal, if required.

GFR (EM2 concept) 850°C

MSR

a
b

700°C–750°C

8%–14% using uranium
carbide fuel in SiC cladding

Water Useb
Similar to LWRs
Similar to LWRs
≈36%–50% less than LWR
because of higher thermal
efficiency≈35%–50% less than LWR
because of higher thermal
efficiency

7%–10% using metallic
fuel with recycle; >40%
once-through≈8% less than an LWR given
slightly greater thermal
efficiency

7%–10% for oxide fuel(much higher proposed forlong-lived cores)

Up to 40% less than LWR
because of higher thermal
efficiency≈32% less than LWR
because of higher thermal
efficiency≈32% less than LWR becauseof higher thermal efficiency

Atom% designates the percentage of fissile and fertile atoms that underwent fission in the fuel.
Defined as water use per unit electricity generated with respect to a LWR with 33% efficiency using the formula(1-η)/η, where η is the thermal efficiency of the plant.

Safety Characteristics
The safety of a nuclear system can be thoughtof as a series of safety functions that must be
satisfactorily accomplished to control the reactor
when it is operating normally and to remove
decay heat when the reactor is shut down, thereby
preventing the release of radioactive material
to the environment in the event of an accident.
Controlling the inadvertent release of radioactive
material to the environment requires that theenergy sources that can mobilize the material
be minimized or controlled. This leads to thefollowing key safety functions:• Control of nuclear reactivity (reactor startup,
operation, and shutdown),• Assurance of heat removal to an ultimate
heat sink,• Control of coolant inventory (to prevent lossof coolant),• Minimization of chemical energy release (e.g.,
from ingress of air and/or steam, or otherchemically reactive fluids), and• Reliability of mechanisms for actuating andoperating the engineered safety systems.
To achieve a low level of risk from accidents,
advanced reactor designs must have safety
features and systems that show physicalseparation, independence, diversity, andredundancy with defense-in-depth to cover
the potentially unanticipated risks that can arise
from an incomplete understanding of reactor
system behavior.
Historically in LWRs, safety functions wereaccomplished with a diverse and redundantcombination of backup safety systems andalternative sources of water to reduce thelikelihood and mitigate the consequences of achallenge to any of these functions. Regulators
have developed specific reactor design criteria

Chapter 3: Advanced Reactor Technology Evaluation65

to assure that the energy sources that drive
the possible release of radioactive material arecontrolled for a range of postulated design basis
accidents. This design approach has worked in
the sense that current LWRs operate with a highdegree of reliability and safety. Additional safety
features were also installed at nuclear plants
worldwide following the accidents at Three Mile
Island and Fukushima to protect against accidents
beyond the design basis, to further reduce thelikelihood of such accidents and to mitigate any
releases of radiological materials.
Some current LWRs accomplish key safetyfunctions using engineered safety systems
that require electrical power (so-called active
systems1) to actuate valves, water pumps, andspray systems and to achieve containment
isolation. This approach has been followed in someadvanced LWR designs, including the European
EPR design and the Korean APR1400 design.
At the same time, other advanced LWR designs
have evolved to reduce reliance on active systems
and accomplish some needed safety functions
by using natural forces of gravity or gas pressure(so-called passive systems). Examples of thisapproach include the Westinghouse AP1000,
the economic simplified boiling-water reactor(ESBWR), and advanced Chinese and Russian
designs. Finally, the NuScale SMR is a primeexample of an LWR system that is quite innovativein its design. It has virtually eliminated the needfor active systems to accomplish safety functions,relying instead on a combination of passive
systems and the inherent features of its geometry
and materials.
Designs for non-LWR advanced reactor systems
have taken an approach similar to that of the
LWR small modular designs (like NuScale),
implementing and integrating safety functionsin the system design with a decisively greater
emphasis on inherent and passive features thanin current LWRs, as noted in Table 3.3.

1

66

These advanced reactor designs employ different
fuels and different coolants than LWRs. The
selection of fuel, coolant, and moderator (forthermal systems only) affects the inherent
safety of the system through the basic material
properties and chemical characteristics of systemcomponents. Advanced reactor systems haveseveral inherent safety attributes:• Large margin from operating temperature toboiling point for sodium, lead, and molten salt
cooled systems, combined with coolants thathave high thermal conductivity (in the case of
sodium and lead) and high heat capacity.
• Strong negative Doppler coefficient for
HTGR system designs.
• Negative power reactivity coefficient for
SFR and LFR systems (with proper design).
• Robust fuel (TRISO) and high heat capacity
graphite in HTGRs and FHRs.
• Strong fission product retention in sodium,salts, graphite, and, to a lesser extent, lead.
• Low chemical reactivity of coolants such as
helium, lead, and salts.
The inherent safety characteristics of SFRs and
HTGRs have been confirmed through actual
testing in demonstration plants. Designs forthese advanced plants also propose passive
systems for heat removal and reactor shutdown.
These inherent and passive safety characteristics
accomplish three things, the importance of whichcannot be overstated in a post-Fukushima world:• Obviate the need for AC power in off-normal
events, and enable long coping times during
a postulated station blackout;• Simplify overall plant design to allow for fewer
auxiliary components or systems and enable amore automated, streamlined, and potentiallymore effective response to accidents; andActive, passive, and inherent safety features are defined here as follows:
Active safety features require electrical or mechanical power to actuate the safety function.
Passive safety features require only natural forces (gravity or gas pressure) to actuate the safety function.
Inherent safety features derive from basic properties of the material that function as a safety feature.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Table 3.3: Passive safety characteristics of non-LWR advanced reactors
Coolant

HeliumPassive Safety Characteristics
Modular HTGR: Inherent and passive safety because of lower power density coupled with high heat capacityof graphite and passive heat removal from core and reactor vessel. Passive shutdown from negative reactivity
feedback in anticipated transients without scram and other transients has been demonstrated on existingsmaller versions of HTGRs.
GFR: Claims to be passively safe but demonstration will be required. Historically GFRs have had difficulty
attaining high degrees of passive decay heat removal given high power density, low thermal capacity in the core,and poor conductivity of the helium coolant.
Small SFRs: Low pressure pool design to eliminate loss of coolant. Through a combination of reactivity
feedbacksa from enhanced neutron leakage, this design achieves a negative power reactivity feedback, whichhelps to control the system under all postulated unprotected (no scram) transients without operator intervention.
Passive safety of these concepts has been demonstrated in tests done at EBR-II. A variety of passive decay heatremoval systems exist that can provide a connection to an ultimate heat sink for the long term.

Liquid Metals

Large SFRs: Designing for overall negative reactivity feedback is more challenging for larger systems given thelower neutron leakage and positive reactivity void coefficient of these types of reactors. Passive heat removal isalso more difficult given the decay heat load and lower surface-to-volume ratio of the reactor vessel comparedto small SFRs.
LFR: Lead provides a large heat sink, especially in unprotected events. Reactivity feedbacks prevent severe
accidents, similar to SFR approach. However, because the Russian LFR was built for submarine service, testingof passive safety systems that is representative of commercial designs would be required.
FHR: Combines passive safety features of HTGR with the large heat capacity and natural circulation capabilities
of molten salt to obtain excellent safety profile. No integral testing of passive safety has been conducted but will
be required.

Molten Salta

MSR: To provide passive safety, drain tanks with a passive fuel plug that will melt if high temperatures occur
under off-normal conditions are incorporated into the design. Drain tanks will have to be designed to avoid
criticality events and to remove decay heat. Integral testing has never been performed to confirm the safety
benefits. Heat content of the off-gas system containing noble gases and volatile fission products needs to beconsidered in design. Holdup of highly radioactive molten salt in reactor piping might severely limit operator
access even after molten salt draining. Fast-spectrum MSRs have large negative temperature and void
coefficients because liquid fuel is expelled from the core if voids are formed or if the temperature increases.
Criticality might occur under accident conditions if the fissile materials were to leak from the primary systemand come near neutron moderators, such as concrete.

Thermal fission reactors use a neutron moderator to slow down (‘thermalize’) the neutrons produced by nuclear fission. The

probability of fission for fissile nuclei such as uranium-235 or plutonium-239 is much greater at thermal neutron energies. In
addition, uranium-238 has a much lower probability of capture than uranium-235 and plutonium-239 for thermal neutrons,
allowing more neutrons to cause fission of fissile nuclei and propagate the chain reaction, rather than being captured byuranium-238. An increase in fuel temperature also raises uranium-238’s neutron absorption by a phenomenon termed Doppler
broadening, thereby providing a rapid negative feedback to help control the reactor. Also, if water is used as a moderator and acirculating coolant, boiling of the coolant will reduce the moderator density and provide negative feedback (termed a negative
void coefficient). Fast reactors use un-moderated fast neutrons to sustain the reaction and therefore require fuel that contains ahigher concentration of fissile material relative to fertile uranium-238. However, fast neutrons have a better fission/capture ratio
for many nuclides, and each fast fission releases a larger number of neutrons, which can be used to convert uranium-238 into
plutonium-239, thus potentially ‘breeding’ more fissile fuel than the reactor consumes. Fast reactor control cannot depend solely
on Doppler broadening and the reactor does not have a negative void coefficient from a moderator. Instead, thermal expansion of
the fuel itself can provide quick negative feedback.

• Have the potential, because of their lower
reactor source terms,2 to reduce the size of
emergency planning zones to the site boundary.
It is important to note that the safety goals andinherent behavior are similar for the less mature2

advanced reactor concepts (LFR, GFR, MSR,
FHR), but these safety attributes still need to
be validated with relevant experimental data
at appropriate scales to support associatedlicensing activities.

Source term is the release of radiological material (e.g., fission products) from the reactor.

Chapter 3: Advanced Reactor Technology Evaluation

67

Despite these positive safety characteristics, somesafety concerns about advanced reactors remain
and will need to be mitigated by design:• Chemical reactivity of sodium with water, air,and concrete (in SFRs).
• Oxidation of graphite by air and/or water
ingress following helium leakage (in HTGRs).
• Reaction of molten salts with moist air toproduce corrosive acids (in MSRs and FHRs).
• Positive void coefficients with some coolants(depends on system design and coolant)(in SFRs and LFRs).

general MSR concept. In the historical regulatory
paradigm, the behavior of the fuel and associatedfission products (quantities, physical and chemical
forms, location in space and time, and integrity
during operations and postulated accidents) needs
to be known with high certainty because it:• Affects operational (operating and design
limits) and off-normal safety aspects of thereactor system (e.g., reactivity control),• Represents an important part of defense-indepth, and• Impacts worker radiation protection.

• High heat content of the off-gas systems that
contain noble gases and other volatile fission
products (in MSRs).

Thus, developing such a basis would help manyof the MSR concepts and is recommended as ahigh-priority technology need going forward.

As discussed in Chapter 5, the U.S. Nuclear
Regulatory Commission (NRC) is developing
safety design criteria for some advanced systems.
As of this writing, the focus has been on thethree most mature technologies: LWR-based
SMRs, HTGRs, and SFRs. In this regard, it is very
important to note that there is no defined safetybasis for licensing a dissolved fuel MSR currently.
This gap presents a unique challenge for the

Beyond these reactor safety characteristics, it isimportant to note that the operational safety ofmany advanced reactor systems cannot be firmly
established today. Developing a cadre of proficient
operators for these new technologies will requirea significant effort because of new man–machineinterfaces, new training requirements, and the lackof operating experience for these systems.

Table 3.4: Operability and maintainability for advanced reactor systems
Coolant

HeliumLiquidMetals

MoltenSalt

68

Operations, Maintenance, and Worker Safety
Modular HTGR: Prior HTGRs have been shown to be operable, and some have had low capacity factors due tomaintenance issues. Radiation dose to workers is very low because the helium coolant is not activated and corrosion
products are minimal.
GFR: Unknown given low technical readiness of concept but use of helium as a coolant and demonstrated reliable fuelshould enable clean operation as a power plant.
SFRs: Prior SFRs have been shown to be operable, but with low capacity factors in many cases. Fuel shuffling andother maintenance activities are more difficult because the coolant is not transparent. In addition, designs must
accommodate the potential for fires when small sodium leaks occur. Engineering solutions have adequately addressedboth of these concerns at SFRs around the world.
LFR: Lead is a toxic coolant so protections are needed for workers when dealing with spills. Lead also has a high melting
point (330°C) so freeze prevention will be a necessary part of the design. Maintenance strategies will have to be
developed to accommodate the high melting point. Coolant activation (producing radio-toxic polonium-210) is also an
issue that must be accommodated in maintenance activities.
Fluoride salts: FLiBe as a coolant has three challenging operational issues: (1) high melting temperature (>460°C),(2) the beryllium (Be) component is carcinogenic, and (3) the lithium (Li) in the salt produces tritium. Freeze protection
will be required in these designs. Strategies to protect workers during maintenance and operation of the system will
also be required. Beryllium in the salt will condense dendritically (BeF2) on cold spots in the system (valve stems,
pump bowl). These dendritic growths break off easily and can be transported in the air. Because it is a high temperaturesystem, in lithium-containing salts, tritium will permeate through hot structures, making tritium control important.
Workers may need respirators and/or tritium bubble suits to perform maintenance and operations depending on
details of the design and its use of tritium control technologies. (Other salts such as sodium-zirconium fluoride havebeen used and do not have these problems.)
MSR: In addition to worker safety issues for FHRs, the circulation of dissolved fuel gives rise to serious radiologicalconcerns for workers. Dose rates near the flowing salt are lethal and must be heavily shielded. The circulation of fueltransports delayed neutrons to the intermediate heat exchanger (IHX), resulting in significant activation. It is unclear
how maintenance and inspection activities will be performed in this environment. Robot electronics may not survive.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Complexity of Operations and Maintenance
The nature of the coolant and its level ofradioactivity and chemical toxicity are importantwhen considering the operations and maintenance(O&M) needs of the integrated system. Examples
of O&M activities include: (a) refueling operations;(b) preventative and corrective maintenanceof mechanical and electrical equipment,
instrumentation and control (I&C), and chemicalsystems; (c) cleanup/recovery from minor spills
and leaks; (d) inspection of key components/
systems as required to meet regulatory
requirements and standards; and (e) coolant
sampling and routine radiological surveys aroundplant equipment. The ease (or, conversely, thecomplexity) of maintenance, inspection, anddecontamination of plant components impacts
worker safety. The physical layout and size(or compactness) of the overall system design
also affects ease of access for maintenance.
In addition, all of these factors affect the overall
reliability of plant systems and the availabilityof the reactor. Table 3.4 summarizes operability
and maintainability aspects of these systems.
Several key observations concerning the O&M
requirements of advanced reactors emerge fromthis brief technology review:• Operational exposure to radiation for systems
will be reduced (relative to LWRs) for systems
that use very high-quality fuel and graphite(e.g., TRISO fuel in HTGRs).
• Some coolants (sodium, salt, lead) produce
activation products that must be addressed
during maintenance operations:– Sodium-24 for sodium coolant andsodium‑bearing salts,– Tritium for lithium-containing salts, and– Polonium-210 for lead (even more so
if bismuth is used to reduce the melting
point of the lead coolant).
• Some coolants (e.g., lead, beryllium-containing
salts) are chemically toxic and require
special attention to worker protection duringcommissioning and O&M activities.
• Because MSRs contain dissolved fissile material
and fission products in the salt coolant,
radiation levels for MSRs are significantly

higher than in other advanced reactor concepts(in some cases they are lethal). This willlead to serious challenges for in-service or
out-of-service inspection and maintenanceof components (heat exchangers, pumps,
reactor vessel).
• Coolants that can freeze at high temperatures(e.g., salts, lead) will require refueling atelevated temperatures and will rely on highly
reliable engineered systems to prevent freezingin order to ensure coolant flow as well as toprotect the vessel and other components in thesystem that may not be able to accommodate
freeze-thaw cycles.
• High temperature coolants (salt) andnon-transparent coolants (sodium and lead)can make refueling (if required) and in-service
inspection difficult; however, engineeringsolutions are available.
• Leak protection/minimization for all of thesesystems (e.g., sodium) must be provided.

Finding:

In advanced reactors, the combination offuel, coolant, and moderator results in a setof core materials that has high chemicaland physical stability, high heat capacity,
negative reactivity feedbacks, and highretention of fission products. In addition,these systems include engineered safetysystems that require no emergency AC
power and minimal external interventions.
This type of design evolution has alreadyoccurred in advanced LWRs and is exhibitedin new plants built in China, Europe, andthe United States. These design attributes
will make plant operations much simpler
and more tolerable to human errors,
thereby reducing the probability that severe
accidents occur and drastically reducing
offsite consequences in the event that theydo. Their improved safety characteristics canalso make licensing of new nuclear plants
easier and accelerate their deployment indeveloped and developing countries.

Chapter 3: Advanced Reactor Technology Evaluation693.2 ASSESSMENT OF COST ESTIMATES
FOR ADVANCED REACTORS
Advanced reactor costs are much more difficult
to establish because of a lack of design detail,different historical bases for the construction ofthese systems, and variations in the assumptions
used to estimate costs. We relied solely on open
sources for estimates of overnight capital costs
and not on industry sources so that we could
compare cost projections for different advanced
reactors in an internally consistent manner.
The results of our analysis are presented inTable 3.5; more detail is provided in Appendix K.
Estimates of projected cost are based on
traditional stick-built construction in the UnitedStates for a NOAK plant. The NOAK plant isassumed to be identical to the FOAK plant
supplied and built by the same vendors andcontractors with only the site-specific scopealtered to meet the needs of the NOAK plant site.
Costs for NOAK plants are achieved only after
many such reactors (approximately eight in thecase of large reactor plants and many more in thecase of smaller plants) have been constructed
for a particular nuclear energy system (Economic
Modeling Working Group 2007). For comparison,
the current FOAK overnight cost for NuScale,a small LWR, is projected to be approximately$5,100 per kilowatt of electrical generating
capacity (kWe). Projected costs for HTGR
(Gandrik 2012) and SFR (Ganda 2015) systems
are based on the most current estimatesavailable from open sources. These estimates

are considered more reliable because such
systems have been built in the past and are basedon conceptual designs that have evolved overthe past 25 to 30 years. Cost estimates for FHR(small (Andreades 2015) and large (Holcomb2011)) and MSR (Engle 1980) systems arehighly uncertain because they are based on earlypre-conceptual designs.
Direct costs in Table 3.5 include costs for reactor
and turbine plant equipment and labor costs for
installation, the cost of civil works to prepare thesite and its buildings and structures, and the costof electrical and miscellaneous equipment andassociated labor costs for installation.
Indirect costs include several sub-categories
of cost:• Construction services—including but notlimited to costs for construction management,
procurement, scheduling, cost control, site
safety, and quality inspections.
• Home office and engineering services—
including but not limited to costs for estimating,scheduling, project expediting, projectgeneral management, design allowance,and project fees.
• Field office and engineering services—including
but not limited to costs for the field office, fieldengineering, field drafting, field procurement,
and field administrative and general expenses.

Table 3.5: Comparison of projected NOAK advanced reactor capital costs, including contingency to accountfor level of design maturity and uncertainty (to two significant figures)
Cost ($/kWe)
Machine Sizea
Design Stage
Direct Cost
Indirect Cost
Contingency
Total Overnight
Cost
Interest During
Construction
Total Capital
Invested
a

70

HTGR
4 × 600 MWthConceptual
approaching
preliminary
2,400
1,400
800

SFR
4 × 840 MWthConceptual
approaching
preliminary
2,500
1,600
800

FHR (Large)
3,400 MWthFHR (Small)
12 × 242 MWthMSR
2275 MWthEarly
pre-conceptual

Early
pre-conceptual

Early
pre-conceptual

2,100
1,400
1,100

2,300
1,300
1,100

2,500
1,700
1,200

4,600

4,900

4,600

4,700

5,400

600

700

600

700

700

5,200

5,600

5,200

5,400

6,100

Reactor size is given in megawatts of thermal output (MWth)THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD• Owner’s costs—including but not limited toproject fees, taxes, and insurance; spare partsand other capital expenses; staff training andstartup costs; and administrative and general
expenses but not interest during construction.
• Design costs—including preconstructionengineering, design, and layout work associatedwith the site.
Given limited experience in the constructionof advanced reactor systems, indirect costs(oversight on installation, home and fieldengineering, and construction services) are
expressed as a percentage of direct costs. Slightly
different values were used for the indirect cost
multipliers in the cost assessments for different
reactors: 57% was used for the HTGR and 64% for
the SFR. Indirect costs for the small FHR arebased on those for the HTGR. Large FHR costs
were escalated to current costs based on thework of Ganda, Hansen, et al. (2016). MSR direct
costs were based on an early-1980s vintage
pre-conceptual design escalated to current costs
using estimates for LWR direct costs from thesame time period. To make a fair comparison weused the indirect cost percentage of the large FHR
for consistency. As noted earlier, indirect costs
taken together are a large part of the overall cost.
Estimates of actual indirect costs as a percentage
of direct costs from the historical LWR fleet spana large range. In some cases, the ratio has been
as low as 20%, but a best-practices value fromthe LWR fleet is about 40% whereas the fleet
average is 50%. Cost estimates developed by the
U.S. Department of Energy (DOE) (1980) (1988)
suggest an indirect-to-direct cost ratio of 51%
for reactors built prior to the Three Mile Island
accident and 77% for reactors built after Three
Mile Island. The International Atomic Energy
Agency (1978) recommends a value of 52%. Thus,
the values used here are considered reasonable
based on the open literature on this topic.
A variable contingency is provided for theseestimates based on the maturity of the designs,
associated technology development, and supply
chain considerations. Mature concepts that areapproaching the level of preliminary design (HTGR
and SFR) were thus assigned a contingency of

20% while early, pre-conceptual designs wereassigned a contingency of 30% to reflect thelower level of technical detail in these designs.
As discussed later, these percentages may beconsidered low, especially for the lower maturity
concepts where some significant design detail isabsent. Nevertheless, these contingency values
are used here primarily for comparison purposes.
Finally, all systems were assumed to haveconstruction times of 60 months and be subject
to an interest rate of 8% (based on 50% debt and
50% equity financing and 30-year economic lifeof the plant) for purposes of calculating financing
costs during construction and the levelized costof electricity (LCOE).
With these assumptions and the low levelof design detail available for some concepts,
projected overnight costs for all the advanced
reactors we considered appear to be within arange between $4,600/kWe and $5,400/kWe.
Given the uncertainty in these values, slightdifferences in the approach used to project costs
for different concepts, and the methodology
used to normalize costs to the current decade,differences between the cost estimates for different
advanced reactor concepts are not considered
substantial or meaningful. These estimates are
consistent with the cost expectations expressedby experts on Generation-IV systems (Anadón,
et al. 2012) and are somewhat lower than costs
estimated by the Generation-IV International
Forum (van Heek, Roelofs, and Ehlert 2012). More
importantly, the actual costs of these systems
when built will depend on the construction
management practices applied to new builds inthe future: as discussed in Chapter 2, the reactor
design is secondary. As with the LWR fleet, costs
could be lower in international markets where
lower rates for labor and different levels of laborproductivity apply; costs could also be lower if
the new construction approaches discussed in
Chapter 2 are adopted and succeed in reducing
installation costs and project timelines.
Figure 3.3 compares projected LCOEs for eachadvanced reactor concept and for advanced LWRs,
assuming a uniform capacity factor of 90% for
all concepts. Fuel costs for HTGRs (TRISO fuel)Chapter 3: Advanced Reactor Technology Evaluation

71and SFRs (metallic fuel) are significantly higher
than for current LWRs, in part because these fuelsrequire higher enrichment but also because they
involve different fabrication methods. Neither typeof reactor has been deployed yet on large scale sofabrication cost reductions might be possible in
the future. For FHR fuel costs, the costs originallyprojected for both small and large systems thatuse TRISO fuel were underestimated and werecorrected based on the HTGR cost estimate,which comes from vendor quotations. Detailed
cost estimates for MSR fuel were not available but
a nominal value was used based on the level ofuranium enrichment required for the system.
For a small FHR with the NACC, projected costs
assume operation with natural gas 50% of thetime. This mode of operation boosts the thermal
power output for an individual unit operating at
100 megawatts of thermal output (MWth) and
53% efficiency in reactor-only mode to 242 MWthand 70% efficiency for the reactor and natural gas
firing mode. The estimate also includes the costof natural gas associated with the NACC, whichis assumed to be $3.40 per megawatt hour ofelectrical output (MWhe)—only about 10% of the
O&M costs. Higher O&M costs are associatedwith a large staff at each of the individual units.

Operational costs are generally similar except forthe small FHR, a 12-module plant for which costs
were estimated by scaling from the HTGR. Had
a common cost for O&M been used, all of thesystems would have an LCOE of approximately$110/MWhe–$115/MWhe. These values areslightly higher than the $92/MWhe–$100/MWhecost estimate for advanced LWRs provided by the
U.S. Energy Information Administration (2016);
they are also higher than the NuScale estimate(Surina 2016) of $96/MWhe–$106/MWhe.
Reduced interest rates and shorter construction
times could reduce the LCOE values presented here.
These projected costs for advanced reactor
systems are also very comparable to the costlevels required for nuclear energy to compete in
U.S. electricity markets under a fairly aggressive
carbon constraint, based on the analysis discussed
in Chapter 1—specifically, under an emissions
limit of 50 grams carbon dioxide per kilowatt hourof electricity generation (gCO2/kWhe) or lower.
While all the advanced reactor concepts currently
being considered can produce electricity, the key
question is which reactor concept is best suited to
producing electricity cheaply. For the most part, theanswer comes down to which reactor concept has

Figure 3.3: Projected LCOE for different advanced reactor concepts
Levelized Cost of Electricy ($/MWe-hr)

160.00140.00120.00100.00
80.00

Fuel
O&M

60.00

Capital

40.00
20.00
0.00

72

HTGR

SFR

Large FHR with MSR
FHR
NACC
Reactor Concept

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

ALWR

NuScalethe lowest capital cost. All nuclear systems face thesame fundamental challenges with respect to cost.
As discussed in Chapter 2
on the industry’s cost-reduction opportunities, costdifferences between any of the advanced reactor
concepts and the expensive incumbent LWR
designs may be small if reactors continue
to be built on a large scale at construction sites
in countries with low productivity and high wages in
the construction sector. However, many of the newcapital cost reduction opportunities reviewed in
Chapter 2 are potentially applicable to all thedifferent reactor concepts. All of these concepts canbe realized in smaller reactors and by using reactor
components that can be factory made, to reduce
the portion of plant installation that has to becompleted on site. All the designs can use seismic
isolation. All have the potential to exploit passive
safety principles and each reactor type can exploit
the unique safety features that are inherent to its
particular design. However, without these costcutting innovations, we do not see that any of theadvanced reactor concepts offer inherent potential
to significantly reduce the cost of nuclear electricity.
Finding:

Technology advances in plant design, notin the reactor, hold the greatest promisefor reducing capital cost. All the broadly
discussed reactor concepts, including
incumbent LWR technology and several of
the Generation-IV designs, can potentiallyexploit many of these advances. The
challenge for any proposed plant design is toachieve the radical cost reductions needed
to make a new nuclear plant competitive inthe on-grid electricity market.

Uncertainties and Contingency
It is critical to stress that the uncertainty in current
cost estimates is large, given the lack of design
detail underpinning projections of overnight
cost and LCOE, especially for some concepts
that are at an early design stage. Uncertainty
is accommodated by carrying contingency incosts estimates from the early stages of design.
Table 3.6 presents recommended contingency
ranges from the Association for the Advancementof Cost Engineering International (1997) and theElectric Power Research Institute (1993). Carrying
contingencies of 20% to 30% at the early design
stage is within the ranges recommended for Class 3
and Class 4 cost estimates but values approaching
50% to 100% are recommended for cost estimates
conducted for low-maturity designs (Class 5).
Critical reviews by the RAND Corporation(Merrow, Chapel, and Worthing 1979) (Merrow,
Phillips, and Myers 1981) examined the cost
growth in large engineering megaprojects(chemical, public works, and nuclear weapons)over 35 years ago. The results are relevant
and offer a cautionary reminder about theuncertainty of estimating costs over the courseof a large complex project. Figure 3.4 (left panel)
provides a conceptual illustration of traditional
cost estimates and associated uncertainty as
technologies progress. As greater design detailand additional R&D results are obtained, themagnitude of the uncertainty should decline.
The right panel shows the actual experience oflarge projects superimposed on the conventionalmodel shown in the left plot. The data are plotted
as a fraction of final total project cost. The data
points represent the mean and the uncertainty
bars represent the standard deviation of projects

Table 3.6: Recommended contingency ranges based on level of design maturity
Estimate Class

Maturity Level ofProject Definition
Deliverables

End Usage

Class 50% to 2%Concept screening

Class 4

1% to 15%

Study or feasibility

Class 3

10% to 40%

Budget authorizationor control

Class 2

30% to 75%

Control or bid/tenderClass 1

65% to 100%

Check estimate
or bid/tenderMethodology

Expected
Accuracy Range

Capacity factored, parametricmodels, judgement, or analogy
Equipment factors or parametricmodelsSemi-detailed unit costs withassembly level line items
Detailed unit cost with forced
detailed take-off
Detailed unit cost with detailed
take-off

Low: -20% to -50%
High: +30% to +100%
Low: -15% to -30%
High: +20% to +50%
Low: -10% to -20%
High: +10% to +30%
Low: -5% to -15%
High: +5% to +20%
Low: -3% to -10%
High: +3% to +15%

Chapter 3: Advanced Reactor Technology Evaluation

73

Figure 3.4: Cost estimation in large complex projects showing that as designs mature and incorporate more detail,cost uncertainty decreases but (more importantly) actual cost increases significantly

examined in the study. As uncertainties decline,
overall cost grows significantly, suggesting animplicit low bias in early cost estimates for large
megaprojects. The tendency of early estimatesto understate costs can be attributed to several
factors: (a) how different (and unproven at scale)the new technology is compared to past plants,(b) insufficient project definition—in terms ofdetail and comprehensiveness—to perform asound cost estimate, and (c) project complexity.
Other experts who study megaprojects claim thatbeyond these technical reasons, optimism bias
(a cognitive predisposition to judge future eventsin a more positive light than is warranted by actual
experience) and strategic misrepresentation(deliberately and strategically overestimating
benefits and underestimating costs to increase
the likelihood that a given project, and not thecompetition’s, gains approval and funding) are
additional reasons why early cost estimates are
not good predictors of the ultimate cost of large
projects. Appendix L provides more detail about
the characteristics of megaprojects in generaland nuclear power plants as a prime example
of such projects.

74

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

The cost patterns seen in other technologies arealso relevant to advanced reactor systems, asevidenced by large increases in projected costs
for a number of reactors and shown in the rightpanel of Figure 3.4. Advertised overnight costs
for the AP1000 have increased from a “certified”
public utility commission value of approximately$4,500/kWe to $8,600/kWe. Early pre-conceptual
cost estimates for NuScale were $1,200/kWe(Modro, et al. 2003) but are now projected tobe approximately $5,000/kWe (Perez 2017).
Projected costs for more mature advanced reactor
technologies (sodium or gas cooled reactors) haveincreased similarly. A cost of $1,365/kWe wasreported for modular HGTR systems (Universityof Chicago 2004) more than a decade ago but
the projected cost estimates shown in Table 3.5
are about three times this value. Early estimatesof overnight cost (Shropshire 2009) for a
PRISM type SFR reactor were approximately$1,300/kWe but are projected to be closer to$5,000/kWe in Table 3.5. These increases are
too large to be attributed solely to cost escalation
for labor and commodity inputs. Instead, theyhighlight the enormous difficulty of accurately
predicting the actual cost of new technologies
at early stages of design conception.

Finding:

Traditionally, early-stage cost estimateshave been significantly biased toward
underestimating costs and hence havebeen unreliable predictors of the eventual
cost of a given nuclear technology once
its technical readiness increases and thereactor design matures. Nevertheless, ourassessment of advanced reactor systems
suggests that these systems have thepotential to exploit inherent and passive
safety features to improve overall safety andoperation. These systems have promise,but their economic potential is not yet
proven. A commitment to explore and test
advance reactor technologies may provide
significant economic benefit for future
electricity systems.

3.3 POTENTIAL APPLICATIONSFOR ADVANCED NUCLEAR
ENERGY SYSTEMS
Because of their technical characteristics,
advanced nuclear technologies are being
explored not only as potential generators ofcheap electricity, but also for their potential toserve other product missions including supplying
process heat for the production of chemicals,
synthetic fuels, and hydrogen or for water
desalination. In addition, some advanced nuclear
technologies have the potential to be used in
microgrid applications and actinide transmutation,
as shown in Table 3.7. Of the diverse applications
shown in Table 3.7, the generation of cheap,
grid-connected baseload electricity is potentiallythe most consequential and is therefore
generally assumed to be the primary mission
for most advanced nuclear energy systems.
The combination of inherent and passive safetycharacteristics and higher thermal efficiency may

Table 3.7: Recommended contingency ranges based on level of design maturity
Application
Generation of Electricity
for Delivery to the Grid
Process Heat for
Producing Hydrogen,
Synfuels, and Other
Chemicals
Variable Power
Instead of Baseload
with a Topping Cycle
Water Desalination
Power and Heatto Microgrids

Actinide Transmutation(fuel cycle mission)

Technical Aspects of the Reactor
that Enable Application
The combination of inherent and passive safetycharacteristics and higher thermal efficiency may enablesimpler designs that can exploit modularity and factory
production to reduce cost (as discussed in Chapter 2).
Requires temperatures greater than 600°C for mostapplications. Reactivity feedback from chemical plantto nuclear plant needs to be examined for salt and leadcoolants (not an issue for helium coolant). Developing aheat exchanger at high temperature to meet process heatneeds is key technology challenge.
High temperature is needed for this cycle to be economicallyattractive. Integrating the cycle with the reactor is a key
technology development item.
Works with waste heat and/or electricity from the reactor.

Potentially Suitable
Reactor Concepts
All systems considered here.

Modular HTGR. In principle, LFR,
FHR, MSR, and GFR because of theirhigh proposed outlet temperature,
but with much less certainty becauseof the magnitude of the materials
challenges that must be overcome.
FHR, LFR (high outlet temperatureversion), MSR, modular HTGR,
and GFR.
All systems producing electricity orwith an appropriate, low-temperature
heat extraction loop.
Microreactors of various designs(typically not LWR based).

Very small reactors (<10 MWe) of rugged design, coupled
to ultra-compact power conversion systems such as Stirlingengines, supercritical CO2 cycles or direct conversion devices.
Must be capable of semi-autonomous operations and easy
to transport. Could serve mining sites, remote communities,
offshore platforms, industrial complexes, military bases, orexpeditionary forces.
Fast spectrum is favored over thermal spectrum systems.
SFR, MSR (fast), LFR.
Small probabilities of neutron interaction in fast systems
imply large inventories and multiple recycling passes in
fixed fuel systems to meet transmutation goals. In thermal
systems, destruction of uranium and plutonium is possible
but higher order actinides produced via capture reactions(e.g., americium, curium) are very difficult to manage.
Long-lived cores and fuel qualification remain technology
development issues.

Chapter 3: Advanced Reactor Technology Evaluation75

enable simpler and cheaper advanced reactor
designs that can exploit modularity and factory
production. Reducing the capital cost of advanced
designs is very challenging but necessary.

Cheap, Grid-Connected Electricity
The growth projections discussed in Chapter 1
suggest that electricity demand will increase more
rapidly over the next several decades in Asia thanin the West. In areas of faster demand growth,large LWRs, which are being built efficiently in
Asia, will probably continue to dominate becauseof their ability to quickly add large incrementsof generating capacity. By contrast, many of theadvanced reactor systems are smaller and could
be deployed in regions where electricity demand
growth is more modest or to replace retiring fossilfired generation.
The incumbent nuclear reactor concept—
using light water coolant and a thermal neutron
spectrum—is already being redesigned by anumber of companies that are building SMRs.
A notable example is the design that has
been developed by NuScale Power, which isrelatively well advanced along a path to potential
deployment. In place of one large reactor system
driving the power plant, the NuScale design
substitutes a set of 6–12 smaller, self-contained
reactor modules, which are then aggregated insidea single reactor building and share a single water
coolant pool. While each of the individual modules
is small (50 MWe), assembling 12 modules
in one plant yields a large, 600-MWe power
plant that can compete head-to-head against
incumbent, large-scale LWRs and other generation
technologies to supply on-grid electricity. The useof smaller reactor modules enables increased
reliance on factory production, which is key
to the hoped-for drop in construction cost.
NuScale’s design exploits passive safety features
to eliminate or simplify many systems. According
to the company’s plans, on-site construction of
the reactor building and assembly of the modules
should be much less demanding than building
larger LWRs, allowing the on-site construction
schedule to be reduced to three years. Proponentsof this design argue that the long history of76

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

experience with light water technology justifies
projections that envision a relatively short path to
deployment and scale.
The main economic question is whether an SMR
can be built at a substantially lower unit capital
cost (i.e., per kW of capacity) and therefore
generate baseload electricity at lower total unit
cost (i.e., per MWh). NuScale advertises a capital
cost of less than $5,100/kWe, which is only amodest improvement over the advertised cost ofcertain Gen-III+ systems and still not competitive
against natural gas-fired generation under current
circumstances. A 2016 study performed by Atkins
for the U.K. government estimates the FOAK costof power from integral PWR SMR designs to beabout 30% above the NOAK cost of a traditional,
large LWR. The Atkins study (2016) scales up
companies’ own capital cost estimates to correct
for the ‘optimism bias’ discussed earlier, while also
noting both the potential for sharp cost declines
with volume production of factory builds and theenormous uncertainties involved in attempting toestimate this decline.
Proponents of many small reactor designs also
advertise other advantages besides lower capitalcosts. Some focus on the advantages of smaller
total plant size. They point out that this opens up
sections of the market that are unsuited to large
LWRs of 1 gigawatt (GW) capacity or more. They
also point out that buyers will be better able tofinance capacity purchases in smaller bites.
A note of caution is in order when evaluatingclaims concerning the ancillary advantages ofsmall size. The challenge facing the nuclear
industry is to reduce unit capital cost (i.e., cost perkWe) to be more competitive in generating thelowest unit cost electricity. If the size of a small
plant also happens to be the size that offers thelowest unit capital cost, then the ancillary benefitsof a smaller plant are an extra bonus. However, theextra advantages of small plant size are unlikely tomake up for a failure to radically reduce unit
capital cost.

The problem is that, with respect to size, there isoften a tradeoff between the technically optimal
design and the needs of some customers. Thisis an age-old issue for the nuclear industry, as it
is in many other industries. The optimally-sized
reactor suits some segments of the market, but
not all. Therefore, many reactor vendors size
their technically optimal reactor first, and later
produce smaller versions to serve segments ofthe market to which the most efficient design is
not suited. Among LWR designs, examples of thisapproach include the Russian VBER-300, Holtec’s
SMR-160, and China’s ACP1000. The industry’s
problem is not that it has overlooked valuable
market segments that need smaller reactors.
The problem is that even its optimally scaled
reactors are too expensive on a per-unit-powerbasis. A focus on serving the market segmentsthat need smaller reactor sizes will be of no use
unless the smaller design first accomplishes thetask of radically reducing per-unit capital cost.
If nuclear technology cannot be competitive at
its optimal scale of generation, whether large
or small, it is difficult to see how it will succeedby scaling plants below the optimal size.3 If, on
the other hand, smaller designs are optimal andcan radically reduce unit capital costs, then the
ancillary advantages of accessing a larger market
will be a nice bonus.

Process Heat and High Temperature
Applications
While traditional LWRs operate at relatively low
outlet temperatures, many of the various advanced
reactor designs operate at an array of higher
outlet temperatures. A higher outlet temperature
can improve the thermal efficiency of electricity
generation, which is a valuable feature. As noted
earlier, it also increases electricity output, reduces
fuel consumption, and reduces water usage perunit of energy produced.

Besides their benefits for generating electricity,
high outlet temperatures open up the possibilityof selling the heat itself, which is valuable for otherpurposes. In general, process heat missions favor
reactor systems with higher outlet temperatures,a high degree of safety, low reactor source terms,
and minimum coolant reactivity feedbacks
between the reactor and the process heatapplication—all of which are necessary attributes
for siting a nuclear plant in close proximity to
an industrial facility.
Many nonelectrical uses exist even for the heatproduced by relatively lower temperature LWRs.
For example, a number of existing nuclear power
plants supply district heating systems, and someprovide process heat to industry (International
Atomic Energy Agency 2002). Some of the heatfrom the Soviet Union’s BN-350 fast reactor wasused for desalination. However, many industrial
processes require higher-temperature heat, so
advanced reactors with higher outlet temperature
can expand the potential customer base.
Chapter 2 and Appendix F discuss the current
size of this potential market. While not as large
as the electricity market, the heat market could
potentially support hundreds of small- to mediumsized reactors. In this way, nuclear energy systems
could reduce the large carbon footprint of theindustrial sector in the United States and aroundthe world. The market for process heat could belarger if society becomes more serious about
shifting to hydrogen or synthetic fuels.
Notable experiments with truly high temperature
gas-cooled reactors (HTGRs) began in the 1960s.4
The United Kingdom’s Dragon facility, built in
1964, was used to test fuel and materials andnot to generate electricity. In the United States,
the Peach Bottom 1 reactor, in Pennsylvania,
was an experimental HTGR. It was connected he U.K. National Nuclear Laboratory-led Small Modular Reactor (SMR) Feasibility Study of December 2014T
analyzed two scenarios. In scenario A, SMRs were more costly on a per-unit basis, but they could serve pockets ofthe market that were too small for large LWRs. In scenario B, SMRs were assumed to reach cost parity with large
LWRs and compete head-to-head for the whole market. Interestingly, the U.K. study did not explore the possibility
that SMRs would be cheaper than large LWRs.
4
A large number of operating nuclear power stations have been gas-cooled. Some of the earliest were built in the
U.K. and France starting in the 1950s when the design also produced needed weapons material. A later, advanced
gas-cooled design using carbon dioxide as the coolant became the workhorse for the U.K. nuclear power fleet,many of which remain operational today.
3

Chapter 3: Advanced Reactor Technology Evaluation77

to the grid in 1967 and operated until 1974.
Germany’s AVR was another experimental
HTGR; it was connected to the grid in 1967 andoperated until 1988. A commercial-scale HTGR
was built at Fort St. Vrain in the U.S. state ofColorado and operated commercially from 1979
to 1989. It demonstrated the very high thermal
efficiency achievable in these designs, but also
had operational problems related to the helium
circulator. Germany’s THTR (where ‘TH’ stood forthe thorium fuel) was another commercial-scale
HTGR that began commercial operation in 1987,
but it was permanently shut down the next year.
In 1999, Japan’s experimental high-temperature
test reactor began operation. More recently, China
has been operating a test HTGR known as the
HTR-10. Current plans envision a full commercialscale, six-module version known as the HTR-PM
600. A two-module version is currently underconstruction as Unit 1 of the Shidao Bay Nuclear
Power Plant. It is being built by the Chinese State
Nuclear Power Technology Corporation (SNPTC).
The first of the two Shidao modules is expected tocome online in 2018.
Over the years, the product focus for HTGRs
has varied between electricity generation andindustrial process heat. Early experimental
HTGRs produced electricity, although if theconcept proved viable, it was understood that theprocess heat market was a candidate use. Morerecently, as the problem of climate change hasgrown increasingly salient, the focus has shiftedto industrial process heat. HTGRs were seen
as offering one of few low-carbon options for
supplying industrial process heat. In the UnitedStates, the Energy Policy Act of 2005 establishedthe Next Generation Nuclear Plant (NGNP)
program to develop a very-high-temperature
reactor (VHTR) for industrial purposes. The
mission of the associated NGNP Industry
Alliance is to seek out and promote industrial
uses for HTGR technologies, which provide
high temperature process heat for industrial
applications and which promise to provide newsources of hydrogen and ways to shift chemicaland fuels production to new feedstocks with
reduced greenhouse gas emissions (NGNP
Alliance 2018). However, in light of cheap natural

78

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDgas, the NGNP program is on hold in the UnitedStates. Most recently, there is renewed interest in
using HTGRs primarily as a source of electricity.
The German design adopted for the Chinese
HTR-PM is an example, as is X-Energy’s pebble
bed design. The Chinese project is intended topave the way eventually for a larger-scale plantwith 600 MWe capacity using six reactor units.
China National Nuclear Corporation (CNNC) is
looking to export the new design to Saudi Arabia,
Dubai, and South Africa, among other countries.
Of course, design variants can be optimized forthe electricity market, for the heat market, orfor co-generation.

Flexible Operation
The high penetration of renewables in somemarkets, coupled with natural gas power plants
to provide flexible backup capacity, has replaced
traditional baseload power plants. In such markets,
LWRs may be forced into load-following mode (asis now the case in France and in certain regions of
the United States), and will incur the associatedeconomic penalty for not operating at full capacity
all of the time. To minimize or obviate thiseconomic penalty, any of the advanced nuclear
systems that operate at high temperature could
provide a variable mix of power and heat (or otherenergy products), both to accommodate theintermittency of renewables and to provide power
when renewables are not available (e.g., on cloudy
or windless days), while the reactor would operate
at steady 100% thermal output. It is important tonote that a reactor that produces multiple energy
products at variable levels will, by definition,
be more expensive to build than a reactor that
produces a single product, because the two
product lines must be included in the design.
However, if the second product has more value
than electricity, which is a low-value commodity,
it may be possible to offset the extra investment
cost. Detailed economic analysis would be
required to assess these tradeoffs.
Alternatively, a topping cycle fired by natural gas
has been proposed to provide variable power,
again with the reactor operating at steady 100%
thermal output. As noted earlier, an example
would be an FHR that uses a Nuclear Air-Brayton

Combined Cycle as a topping cycle (Forsberg
2014). This type of system offers a potential new
mission/market for advanced reactors in addition
to traditional baseload electricity generation.
While greater revenue could be expected fromsuch a system because of its higher overall
thermal efficiency compared to a combined cycle
natural gas plant, the cost implications have notyet been evaluated in detail. Furthermore, undera stringent carbon constraint, designs that use
natural gas would not be viable.
A third approach is to use heat storage and thenmodulate the reactor’s electrical output and heatstorage reservoir based on the need (e.g., with asalt loop) (Sullivan 2017). Another innovative idea
for HTGR applications is to operate the plant suchthat the high-heat-capacity graphite in the coreis used to absorb load fluctuations and electrical
output is allowed to vary depending on the helium
inventory control (Yan 2017). Other examplesof thermal heat storage that can be used withany reactor system are discussed in Chapter 2.
Many of these ideas are still at a conceptual stage
and further economic analysis is warranted todetermine their potential market viability.

Microreactors for Off-Grid Electricity
and Heat
Very small reactors (i.e., less than 10 MWe), also
known as microreactors, could provide power and/or heat for a range of microgrid applications,
including to serve mining sites, remotecommunities, offshore platforms, industrial
complexes, military bases, or expeditionary forcesthat need a secure energy supply (Ontario Ministryof Energy 2016). To maximize their utility andminimize their cost, microreactors would have tobe designed for several key features including easytransportation to the site where they will be used,autonomous operation, and ability to be coupled toultra-compact power conversion systems such as
Stirling engines, supercritical CO2 cycles, or directconversion devices. Examples of microreactors
include Kilopower, eVinci, OKLO, and Holos Gen.
5

Scaling reactors down to very small sizes has
certain technological disadvantages. For example,
simply because the ratio of surface area to volume
increases as the reactor becomes smaller, ahigher fraction of the neutrons born in fission
leak out before contributing to the chain reaction.
Additional equipment can be included to reflect
the neutrons back to the core, but this makes thereactor larger and adds to expense and materials.
At the same time, small size also offers potential
advantages. For example, the increased ratio of
surface area to volume makes it easier to remove
heat without recourse to active safety systems. It
may also be much easier to embed microreactors
and to provide seismic isolation.
Potentially compensating for any net diseconomies
of scale is the fact that products for off-gridmarkets can be sold at a much higher price point
than products for on-grid systems. For example,
the main competing technology for off-grid
power is a diesel generator, which has a high unit
cost of power. Therefore, a new microreactor
design could be profitable even where its unit
electricity cost cannot be brought down low
enough to be competitive against other on-grid
generation technologies.
A number of entrepreneurs and investors
are exploring microreactors as a first step ona more viable path to commercializing newreactor technologies. The idea is that off-griduses are an early, more promising market for
the first incarnations of such technologies. The
small size of the reactor not only reduces theinitial investment required,5 it also enables theuse of factory production techniques that canbe gradually improved as production scales.
If success can be achieved initially in off-gridmarkets, then the process of iterative innovation
could open portions of the grid-connected
electricity market to microreactor technology
over time. Such iteration could take two very
different pathways. Along one, microreactors are
scaled up to larger reactor sizes so as to benefit
from economies of scale. Along another, the owever, the very large up-front investment in design, engineering and licensing required for any new reactor
H
technology—on the order of roughly $1 billion—is largely independent of the size of the reactor to be built from the
new technology. The investment can be lower if the design is leveraging an existing technology.

Chapter 3: Advanced Reactor Technology Evaluation79

reactor size remains small and suitable for factory
production, and as unit production costs declinewith cumulative experience, it becomes economic
to assemble many reactors in one plant locationand compete for the on-grid market that way.
Both avenues offer a realistic answer to theimportant question of how a new technology
can overcome financing challenges. They rely ona gradual investment process that is iteratively
driven by commercial considerations andrepetitive adaptation to information garneredalong the way. Many developers find this approach
more plausible and more attractive than a largescale program designed to leap quickly fromresearch to the construction of a multi-billiondollar piece of infrastructure.
A prime example of another technology that has
been successfully commercialized this way is thesolar photovoltaic (PV) module. In this case, too,initial commercial applications centered on off-griduses. As production expanded, PV manufacturers
made gradual improvements in their production
methods. They repeatedly transitioned fromone production method to a new, lower cost
method, which was itself then gradually improved
before being abandoned for another. Costs for
PV modules have continuously declined withcumulative production (Harmon 2000).
Optimism that microreactors can follow the
deployment example set by solar PV modules
must, however, be tempered by the recognition
that there are important differences between
the two technologies. A solar module converts
one form of energy into another, and it generates
little in the way of by-products. A nuclear
power plant produces energy from mass andgenerates a number of by-products that must
be managed, including heat, fission products,
and other components of spent fuel. Many
nuclear power plant systems are built for the
purpose of managing these by-products, and for
doing so under a range of postulated accident
scenarios. Furthermore, maintenance activities
in a radioactive environment are more complex
than in other types of energy facilities.

80

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAs we highlighted in our discussion of costs in
Chapter 2, nuclear island and turbine generator
equipment are not the primary contributors to
the capital cost of a nuclear plant. Rather, it is theon-site construction of the larger plant, including
the installation of the many plant components,that is the main cost driver. Therefore, gaining
efficiencies through the repetitive manufacture of
the reactor itself does not solve the cost problem
for a nuclear plant as a whole. The problem lies in
the larger facility. Where we have emphasized thepromise of factory production and modularization
for reducing nuclear costs, it has been where theyfacilitate improved economics for the plant as awhole, not just the reactor. Applying this insightwill be a challenge for companies interested
in scaling microreactor technology. This is an
important area for research and for innovation inboth design and execution.
From a public policy perspective, it is important toconsider how microreactors serve the objective of
reducing carbon emissions. The off-grid electricity
market is extremely small and makes a tiny
contribution to global emissions, so developing
microreactors to serve this market can only makea small contribution to reducing global greenhousegas emissions. Deploying the technology in
off-grid applications may eventually lead tooptions for addressing the on-grid market, but at amuch later date.
In summary, microreactors designed for highvalue, off-grid uses offer an innovation path thatminimizes the scale of investment needed forearly deployment. Initially targeting a small, but
high-value market reduces the early pressure toachieve immediate success in lowering unit costs.
Rather, it may provide a pathway to realizing cost
reductions over time through experience anditerative re-design. However, there remain sizeable
initial up-front design and testing costs, which
do not scale down linearly with the size of thereactor design and which must be amortized overa smaller, but higher value market.

Desalination
Desalinated water is an increasingly importantcommodity in arid regions of the world that have
limited access to freshwater resources, such as theMiddle East (Lienhard, et al. 2016). Desalination
can be achieved through reverse osmosis,
which requires only electricity or a variety of
low-temperature, heat-based processes. However,the size of the market is quite small: Meetingcurrent global energy demand for desalinatedwater would require approximately 16 GW ofelectric generating capacity, assuming productionof 100 million cubic meters of desalinated water
per day using reverse osmosis with an energy
requirement of 3.5 kWh per cubic meter and a
90% capacity factor for the power plant. This
demand can be easily satisfied by nuclear reactorsthat are generating electricity and/or are equippedwith an appropriate low-temperature heat
extraction loop.

Generation-IV Reactors Targeted to an
Improved Fuel Cycle
A variety of Generation-IV designs advertisefuel cycle benefits, but prime among them
are fast reactor designs. Fast reactor systems
are better suited for actinide transmutation/
destruction than a thermal reactor systembecause of better fission-to-capture ratio in a fast
spectrum than in a thermal spectrum. Althoughfissile isotopes can undergo fission in a thermal
reactor, the probability of capture for fertile
isotopes in a thermal spectrum are large enoughto cause transmutation to higher order actinides(i.e., isotopes of americium and curium) that areeven more difficult to manage than uranium andplutonium in terms of decay heat production andradiotoxicity for reprocessing and disposal.

6

A number of test or experimental or prototype fast
reactors have been built in a number of countries,and some builds have included the provision ofgrid-connected electricity. These include theDounreay dual fluid reactor (DFR) and prototype
fast reactor (PFR) in the United Kingdom,
connected in 1962 and 1975, respectively; Fermi
1 in the United States, connected in 1966; thePhenix in France, connected in 1973; the BN-350
in the former Soviet Union, connected in 1973; theKNK II in Germany, connected in 1978; Monju inJapan, connected in 1995; and the CEFR in China,connected in 2011. The U.S. Experimental Breeder
Reactor II (EBR-II) supplied electricity from 1964
to its closing in 1994. The Prototype Fast Breeder
Reactor (PFBR) is now under construction in India.
Commercial-scale fast reactor builds include
France’s Superphenix, which was connected to thegrid in 1986 and permanently shut down in 1998,
and the BN-600 and BN-800 in Russia, whichwere connected to the grid in 1980 and 2015,
respectively (both are still in operation).6
Performance experience at these reactors has
been varied, which is not surprising given the
prototype nature of the plants and the diversityof designs and missions they represent. Many of
the reactors experienced operating difficulties,
including a few more troublesome accidents that
required long shutdowns, which drove capacity
factors to remarkably low levels.7 For example,
the lifetime capacity factor of Britain’s PFR is
27%. In the United States, Fermi 1 supplied
electricity in only one of the seven short years
of its operating life, whereas EBR-II is said tohave operated smoothly throughout its three
decades of experimentation and utilization andto have achieved a capacity factor of 80% during
the last decade of its life.8 France’s Phenix plant
is considered a success, albeit with a capacity
factor of only 41% over 35 years of production.
By contrast, the Superphenix was a commercial
failure. It produced power in only six years of its

With the exception of the EBR-II, the reactors mentioned here are those included in the IAEA PRIS database.

 xcept as otherwise noted, all capacity factor data are from the IAEA PRIS database (The Database on Nuclear
E
Power Reactors 2017).
8
The EBR-II is not included in the IAEA’s database. The 80% figure is taken from Till and Chang (2011). See also
Koch (2008).
7

Chapter 3: Advanced Reactor Technology Evaluation81

13-year life, with a cumulative capacity factor of
8% before it was permanently shut down.9 Japan’s
Monju fast reactor was another commercial
failure. Shortly after it was started, a sodium
leak and fire forced a shutdown for repairs. A
series of problems kept Monju offline for almost
all of the years it was commissioned before theJapanese government finally made the decision topermanently shut it down. The best performancefor fast reactors has been achieved in Russia.
The BN-350 operated for 25 years, but the IAEA
only has data for the last seven years when thecapacity factor fluctuated between 19% and 72%,
averaging 45%. Russia’s subsequent prototype
fast reactor, the BN-600, has a much better trackrecord over its 35 years of operation to date, witha lifetime capacity factor of 75%. Russia’s new
BN-800 achieved a capacity factor of 85% in thefirst few months of operation.
In the early days of the nuclear power industry,
many analysts predicted that a vibrant market
for electricity generated exclusively by thermal
reactors would quickly exhaust the stocks ofuranium that were thought to be available
worldwide, based on the estimates of that time.
Thus, a chief motivation for pursuing fast reactors
historically was to develop breeder reactorsthat could produce additional fissile material tostretch limited natural uranium resources. In many
countries, this was viewed as a matter of assuring
energy security and sustainability. However, theoriginal logic for fast breeder reactors dissolved
long ago. The uranium resource has proved much
more abundant than had been imagined in themid- to late-20th century, and forecasted industry
growth rates never materialized. Consequently, thecost of raw uranium never escalated as feared, sothat the extra capital cost of fast breeder reactors
has continued to far outweigh any potential
savings on fuel costs (Bunn, et al. 2003) (De Rooand Parsons 2011) (Kazimi, et al. 2011) (Cochrane2010). For this and other reasons, state funding
for the deployment of new fast breeder reactors
disappeared in many countries.10
More recently the focus of research on fast
reactors has shifted from so-called breeders,which maximize the useful recycled fuel produced,
to so-called burners, which minimize the mostharmful waste elements from stockpiles ofspent nuclear fuel—a mission known as actinide
management. Using fast reactors to recycle spent
fuel does reduce the volume and heat load ofspent fuel ultimately destined for final disposal. So,in light of the widely held belief that this would be
the dominant practice in the future, many nations
institutionalized a commitment to recycling intheir national waste management plans. In pursuitof its long-held waste management strategy,
France is tentatively planning to build a newprototype fast reactor, ASTRID, with the supportof the European Union and perhaps Japan. In
the United States, there was interest in making
a future shift to recycling11 but that objective has
waned in recent years, although research in thearea continues. Russia, which has had the mostsuccess in operating fast reactors, plans to build
the commercial scale BN-1200. Russia intends
to be able to offer complete fuel-cycle services,
including waste management, as a critical elementof its commercial export portfolio. Several of thecompanies pursuing Generation-IV fast reactor
designs also advertise reduced waste volumes

 uch of the time that the Superphenix was shut down was because of regulatory reviews and public policyMdebates, so the cumulative capacity factor is perhaps not representative of the reactor’s performance given
the narrowly defined engineering problems it experienced. However, even after eliminating these periods fromthe calculation, Superphenix was available for power generation in only 34 months out of 70, and during thosemonths it was available in only 41.5% of the hours, which yields a total availability of 20%. One analysis points tothe final 16-month operating period and, adjusting certain elements of the usual calculation, reports an availability
factor for this period of 51.3%, “which is an honourable result for a prototype with less than a year equivalent fullpower, and which had not time yet to achieve all the necessary ‘debuggings’” (Guidez and Prêle 2017).
10		While funding for the actual deployment of fast reactors has dried up, several countries have maintained active
research programs targeted to issues such as new fuel designs, new materials, etc., that would be relevant tosome future deployment of reactors of this type.
11		
For example, see U.S. Department of Energy (2003).
9		

82

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDas one of this technology’s advantages, a pointthat has also been made by the U.S. DOE and theGeneration IV International Forum.
It is difficult to make a case for directing researchdollars to innovative designs that focus solely
on breeding to conserve fuel resources or on
burning actinides when the real target should bedesigns that reduce the capital cost of nuclear
energy. Fuel cost is typically only 5% of the total
LCOE for different reactor technologies. Similarly,
the realized or projected dollar cost of waste
management is a small fraction of the LCOE from
nuclear, so reducing the volume of waste hasa very limited potential to reduce the LCOE of
nuclear energy. In fact, an all-in analysis showsthat the extra capital cost of fast breeder or burnerreactors far outweighs any cost benefits fromreducing the volume of waste ultimately sent
for disposal (Bunn, et al. 2003).12, 13 The issue offuel economy or fuel recycling distracts from theessential focus on reducing reactor capital costs,
which account for more than 70% of the total
LCOE for nuclear generation.
Although reduced waste streams cannotmaterially reduce the LCOE of nuclear power,
this feature of fast reactor designs may havean important role to play in public acceptanceof nuclear energy in some countries. Publicconcern about radioactive waste is a critical issue
for nuclear energy, so a case could be made infavor of a system with a different waste stream.
However, it must be admitted that the problemof public acceptance of nuclear energy goes wellbeyond the technical character of the waste issue(including the volume of waste that needs to bedisposed of and the level of hazard it presents).
So, while there might be some modest benefit inengaging public opinion, the problem of public
acceptance remains.

Some research into fast reactor designs is focusing
on improvements to reduce capital costs whileother research is looking at long-lived all-uranium
cores to avoid recycling to obtain fissile material.
Some new fast reactor designs emphasize smaller
size and modularity, which may serve to lower unit
capital cost. Whether cost reductions can actually
be realized has yet to be proven out in practice.
Of course, if a new design could dramaticallyreduce the capital cost of fast reactors, that would
directly lower the LCOE. Any reduction in waste
management costs would be an ancillary benefit.
Recommendation:

Future research, development, anddemonstration (RD&D) funding should
prioritize reactor designs that are optimized
to substantially lower capital costs, including
construction costs. Innovations in fast
reactors that are advertised on the basisof fuel cycle metrics are unlikely to advancecommercial deployment.

Proliferation
In the context of fuel cycles and efforts to limit
the proliferation of nuclear materials or expertisethat could be used for nuclear weapons, thereactor is not the principle concern. Rather, theprimary concerns are associated with uranium
enrichment and/or reprocessing facilities; inother words, the front-end and back-end fuelcycle facilities that could be a source of weaponsuseable materials. Establishing enrichment and/or reprocessing capability is not an economic
choice for small reactor programs. Current IAEA
material control verification activities would
have to be followed for new entrant countries
if they were to employ enrichment facilities for
low-enriched uranium or if they were to undertake
reprocessing. Nevertheless, proliferation willremain an issue of concern for many advanced

 elatedly, proponents have argued for fast reactors as a way to manage legacy stockpiles of nuclear waste—i.e.,R
as an incinerator that produces electricity as a by-product. This argument may have some merit, but it implicitly
concedes that a fast reactor is not cost competitive for producing electricity under other circumstances.
13		
Moreover, most advertisements of the waste reduction benefits credited to fast reactors naively imply
a proportional relationship between volume and cost.
12		

Chapter 3: Advanced Reactor Technology Evaluation83

reactor concepts. Many of them can operate onor have demonstrated the use of alternative fuelcycles using thorium or plutonium. Proliferation
concerns need to be addressed for concepts
that propose to use fuel recycle, for pebble bed
systems, and for thorium-based MSRs that employ
a delay tank to allow protactinium decay to thefissile nuclide uranium-233. In all of these cases,
the concern is the separation of fissile material
in a non-safeguarded form that could be diverted
for nefarious purposes. In particular, on-line
refueling (in the case of pebble bed systems) andliquid-based fuel systems (in the case of MSRs)
need to be considered. These processes resultin new physical reactor configurations that willneed to directly address the intrinsic (physicaland technical design characteristics) and extrinsic(institutional arrangements) measures that are inplace to prevent the theft, diversion, or misuse offissile material. Moreover, additional attention will
be needed at the design stage to develop material
accounting approaches for dissolved fuel systems
given their differences from conventional solid fuelreactor systems. Regardless of the commercial
entity involved and the reactor technology being
considered, safeguards and security measures
will have to be developed to meet IAEA standards
as the design of these systems evolve. This has
been the case for the Westinghouse AP1000, theEuropean EPR, and, more recently, the Korean
APR1400, and it will certainly be necessary if
advanced reactor systems are deployed in the
future on a scale commensurate with deep
decarbonization of energy systems worldwide.
An international methodology to systematicallyaddress these issues is found in Bari (2015).

3.5 TECHNICAL READINESS,DEPLOYMENT, DEMONSTRATION,
AND COMMERCIALIZATION
Several interrelated factors affect the ability tocommercialize an advanced reactor system,
including (a) the readiness of the technologies andsub-systems used; (b) the need for development
activities to mature the technology to the pointthat an engineering demonstration system canbe designed, operated, and licensed; and (c)the feasibility of reaching commercial scale to84

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

confirm that performance, safety, reliability,
and operability meet requirements. This section
reviews the maturity of different advanced reactor
systems, assessing their technical readinessand likely timelines to commercialization.
Table 3.8 summarizes the key technical issues
for each concept with respect to deployment,
demonstration, and commercialization.
A number of organizations around the world
have studied the readiness of advanced reactor
technologies. Although each applies its own
specific scales for the evaluation (Generation IV
International Forum 2014) (Gougar, et al. 2015)(Sowder 2015), broadly the technologies can begrouped according to readiness as follows:• Lowest maturity
LFRs (nitride fuel), GFRs, MSR (fast) and MSR(thermal using salt other than FLiBe)• Low to moderate maturity
Advanced SFRs, FHRs, MSRs (thermalusing FLiBe), LFRs (oxide fuel), VHTRs(900°C outlet)• Moderate to high maturity
Small conventional SFRs and modular HTGRs(750°C outlet)
These ratings are based on three primary criteria:(a) the extent of further technology development
needed to resolve technical, design, and/or
licensing issues, especially for fuels, cladding,coolants and/or moderators, and combinations
thereof for which little to no data exist on their
behavior in a neutron flux and/or at prototypicaltemperatures and mechanical stresses; (b) priorsuccessful operating experience with the
integrated system (or one similar to it); and(c) the level of existing safety demonstration of
the system or its key components/subsystems.
In general, the technology development issues
identified in Table 3.8 for lower maturity options
are related to the viability and performance
confirmation of key reactor features (fuel, coolant,
structures), whereas the technology development
issues for higher maturity options are related
to licensing qualification and extension to new
performance regimes.

Table 3.8: Advanced reactor operating experience, technology development issues, and technical readiness
Coolant

Technology and Prior
Operating Experience

Technology
Readiness Level

Outstanding Technology Development Issues

Small HTGR; half dozen
around the world

Moderate to high for
750°C outlet design;
Low to moderate
for 900°C outlet
temperature design

For designs with 750°C outlet temperature, complete fuel andgraphite qualification by 2022. For 900°C outlet temperature,additional work is required for intermediate heat exchanger
and other system components that can operate at that hightemperature.

GFR; none

Lowest. A gas-cooled Fuel requires qualification. Internal structures must be able tofast reactor has never sustain high levels of radiation damage for the long-lived cores
been built anywhere
being proposed. Safety systems require demonstration.
in the world

Small SFR like PRISM
or ARC; several dozens
around the world

High for traditional
small SFR. Medium
for longer lived,
higher burnup breedand-burn cores or for
SFRs using advanced
steel alloys that have
yet to be qualified

Source term experiments for metallic fuel to reduce
conservatism in safety analysis. Major fuel qualification effort
if reactor is to be used with transmutation fuel. Developmentof a fuel vendor for commercialization. For more advanced
SFRs, longer lived, higher burnup breed-and-burn cores need
to be demonstrated and concepts using advanced structural
alloys need to be qualified

LFR; Russian subs
(none elsewhere)

LowestCorrosion and erosion of coated cladding by lead at higher
temperatures (≈700°C–750°C outlet) and higher flow
velocities. Testing of passive safety behavior of the plant/key
systems. Major qualification effort is needed for transmutationfuel (if reactor is used in that manner). Some concepts favor
the use of nitride fuel—qualifying this fuel system in an LFR
would require a significant effort and increase time to reachcommercial readiness.

FHR; none

Low to moderate

Prove REDOX corrosion/control in non-uranium-based salt in
the presence of a neutron field. Need a demonstrated material
solution (strength, corrosion resistance, irradiation stability)
for long-term operation. Demonstrate tritium mitigation
solution. Test passive safety aspects of the plant/design.

MSR thermal; twothermal experiment
systems (MSRE and
ARE). No power
conversion in theseexperiments

Low to moderate for
FLiBe-based thermal
reactor systems. Low
for other salts in both
thermal and fast
spectrums. Most
systems outside thereactor dealing withremoval of fission
products, actinides
and fissile/fertilematerial are low
maturity. Suchsystems are needed
to maintain reactivity
at high burnup. Manyof these proposed
reactor systems have
not yet been built
anywhere in theworld.

Depending on the design, long-term corrosion is an issue
unless major components are replaced frequently as is
proposed in some designs. Demonstration of REDOX control ina neutron field in the salt will be required if the salt is not FLiBe.
For lithium-containing salts, tritium mitigation solution must
be demonstrated. Behavior of noble fission products platingout in IHX and corrosion and embrittlement by fission producttellurium (leading to cracking) over longer operation are also
uncertain. High nickel alloy (Hastelloy X) developed at Oak
Ridge National Laboratory in the United States is not code
qualified for use by the American Society of MechanicalEngineers (ASME). This alloy also has poor irradiation stability
and insufficient strength above 700°C. A demonstrated
material solution is needed for long-term operation.
(Some designers propose replacing structural materials every
4 to 6 years for this reason with an associated increase in costand reduction in availability.) Unclear how inspection
requirements per ASME Section XI will be implemented.
Instrumentation in this system will require some development.
Proliferation and materials accounting issues remain in thissystem since fission products and actinides are removed fromthe system and fissile material can in principle be diverted.

MSR fast; no fastsystems have everbeen built

Lowest.
Similar concerns asthermal MSRs

Chloride salts, strategies for corrosion control must be
demonstrated. A materials solution must be demonstrated.
Similar issues on inspection as MSR thermal systems.
High power densities in some systems require high flow rates
that can lead to erosion/corrosion concerns. Also, high flow
rates can lead to very low delayed neutron fraction in the core,
which makes reactivity control problematic.

HeliumLiquid Metal

Molten Salt

Chapter 3: Advanced Reactor Technology Evaluation

85

Historical Experience
Historically, nuclear energy systems (LWRs, SFRs,
and HTGRs) have passed through a number ofdevelopmental steps prior to commercialization,
as shown in Figure 3.5 (Petti, et al. 2017):• Research and development to prove thescientific feasibility of key features associatedwith fuel, coolant, and geometrical reactor
system components and configurations.
• Engineering demonstration at reduced scale
for proof of concept for designs that havenever been built. The goal at this stage is todemonstrate the viability of the integrated
system. Historically, these engineering
demonstrations have involved very small
reactors (less than 50 MWe).
• Performance demonstration(s) to confirm
effective scale-up of the system and to gain
operating experience to validate the integral
behavior of the system (including the fuel cycle
in some cases) resulting in proof of performance.
• Commercial demonstrations that will be
replicated for subsequent commercial offerings
if the system works as designed.
We have deliberately avoided the terms‘demonstration,’ ‘prototype,’ or ‘first-of-a-kind,’ indescribing these steps, since these terms can besomewhat ambiguous depending on the context
in which they are used. In almost all cases, newreactor systems historically were connected to thegrid to enable electricity production during thisdevelopment process. Similar development steps
apply in the chemical and offshore oil industries.
Similar steps are needed, particularly for theless mature technologies (i.e., LFR, FHR, MSR,
and GFR), to complete required technology
demonstration activities, gain operating
experience, demonstrate effective systemscale-up, reduce commercialization risk, andestablish mature supply chains. These items are
all important prerequisites for establishing viable
commercial offerings for these technologies. Basedon the maturation trajectories of the Integral Fast
Reactor project (Till and Chang 2011), which led to
GE’s PRISM design; the NGNP project (and earlier
U.S. DOE funding of HTGR programs), which led toa mature HTGR (Idaho National Laboratory 2011);
the NuScale small modular LWR (McGough 2017);
and estimates of the R&D necessary to advance
MSR technology (Engle 1980) in the United Statesin the late 1970s, the cost and time required tomature a nuclear technology is significant: in therange of $1–$2 billion per concept, corresponding
to several million person-hours of design/
engineering work and 15–20 years to get to thepoint where a coherent validated demonstration
system can be designed with the level of technicalconfidence demanded by regulatory authorities.
In our assessment, an initial commercial offering
could occur in 2030 for SFRs and HTGRs, withfollow-on commercial units between 2030 and
2050. Early-phase developmental machines could
be anticipated in the 2030–2040 timeframe
for the less mature technologies.

Figure 3.5: Historical paradigm for commercializing new nuclear power technologies(Petti, et al. 2017)86

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Figure 3.6: Notional advanced reactor development schedule for less mature technologies based on
historical practice
Critical Technology
Development Testing(Out of Pile and In-pile Testing)2025

8 years

Design, license andbuild machine
10 years; 7 years beyond dotted line

Operateengineering
demonstration
5 years

Design, license andbuild scaled up machine

Supply chain development

10 years; 7 years beyond dotted line

7 years

2020

2037

2025

2030

2035

2040

Operate scaled up
performance
demonstration
5 years

2045

2049

Subsequent commercial
offerings (beyond 2050)

2050
18-GA50013-04

Test beds also need to be established for theseless mature technologies. In particular, sufficient
single-effects feasibility R&D to resolve someof the issues in Table 3.8 is a critical bottleneckthat must be overcome early in the development
process to enable the low-maturity technologies
to progress to the next step of technology
readiness. Properly scaled out-of-pile loops canhelp qualify the components outside the reactor
itself (e.g., steam generator, intermediate heatexchangers, pumps, valves).
In-pile experiments and test loops can be used toqualify components (e.g., structural materials, fuel,control rod sleeves, moderator rods) that must be
exposed to the actual environment in the reactor
core to assess issues related to material swelling,
component performance (e.g., degradation,
corrosion, stability), and lifetime. Development
and qualification of fuels and materials for fast
reactors such as the lead-cooled fast reactor andchloride-salt fast reactor concepts will require
irradiations in test reactors with significant fastneutron fluxes—i.e., on the order of 1015 neutrons
per centimeter squared per second (n/(cm2-sec))
and higher. Such capability currently does notexist in the United States. However, fast-neutron
test reactors are available in Russia and will soon
be available in China, India, and possibly France.
If agreements can be reached to collaborate
with any of those countries, there may not be acompelling reason for the United States to develop

a domestic duplicate. Furthermore, it is worth
noting that development and commercializationof most of the Generation‑IV systems does
not require a fast-neutron test reactor because
their fuels and materials are either alreadyqualified (for example, in the case of traditional
sodium‑cooled reactor designs) or the expected
fast neutron fluxes are low (in the case of all
thermal‑neutron reactor designs).
Reduced-scale engineering demonstrations may
be necessary for systems that have never been
built before to understand the integrated behaviorof the system prior to scale-up to a performance
demonstration of commercial size. In the UnitedStates, DOE’s national laboratories are thelogical location for developing these capabilities
in collaboration with private industry. Similar
research laboratories exist in other countries thathave established nuclear energy programs.
While this traditional process for nuclear reactor
development has been used in the United States
and around the world for LWRs, sodium-cooled,and gas-cooled reactors, it is very lengthy.
Figure 3.6 illustrates a typical development
timeline based on historic experience. Whilesome of the original LWRs back in the 1960s wereable to complete this approach in 13 to 15 years,
today the process can be expected to take much
longer because of the increased level ofknowledge needed to comply with regulations,

Chapter 3: Advanced Reactor Technology Evaluation

87

the introduction of codes and standards (e.g.,
Institute of Electrical and Electronics Engineers(IEEE) Class 1E, ASME Section 3) that did not exist
when nuclear power was first developed, and thegreater assurance of performance demanded byinvestors given the magnitude of the financial
resources required at each step.
Of particular importance is the need to mature
the supply chains for advanced reactor systems.
These reactors use different fuels, coolants, andmoderators and thus only some of the existing
LWR supply chain is relevant. For example, fuels
used in almost all of the advanced systems
require uranium enrichments greater than thecurrent licensed limit of 5% in the United States.
Currently, down blending of highly enricheduranium (HEU) is used for current research needsin the United States (BWXT and Y-12 provide
these services for various DOE fuel programs.)
There are no large commercial-scale fuel cycle
facilities anywhere in the world that can deliver
such feedstocks, termed ‘high assay low enricheduranium’ (HALEU) (Schnoebelen and Kick 2017).
While the centrifuge technology used to enrichuranium is certainly capable of producing 20%
uranium-235, there are two very long lead-time
aspects to actually delivering HALEU: the processof licensing such facilities (due to issues related
to criticality and materials safeguarding) andsecond, commercial-scale transport packages
for most chemical forms of HALEU must also be
designed and licensed. This second aspect could
require a decade-long project. It might be avoided
or minimized by co-locating enrichment, chemical
conversion, and fabrication facilities at a single
site to avoid the need to transport intermediate
uranium products on public highways. Anotherexample of a supply chain challenge involves
pumps for sodium, lead, and salt systems andcirculators for gas-cooled reactors. These are
unique components that will require industrial
capability to be developed and demonstrated.
Based on numerous studies of the technology
readiness of different advanced reactor options,the maturity of the underlying technologies,
and the amount of information (a mixtureof operating experience, testing, data, and88

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

analysis) necessary to complete a validated
design under existing licensing rules, commercial
deployments (the initial commercial deployment
and subsequent commercial units shown in theblue box in Figure 3.5) can be expected in thefollowing timeframes:
ReactorTechnology

Initial Commercial
Deployment

Subsequent
Commercial Units

NuScale andother LWR SMRs

Between now
and 2030

Between 2030
and 2050

SFRs and HTGRs

2030

Between 2030
and 2050

FHRs, MSRs,
LFRs, VHTRs, and Beyond 2050
advanced SFRs

Beyond 2050

Recognizing that these are very long timelinesthat effectively require governments to invest
in advanced nuclear technologies (given therisks and timelines involved, no other entity
is likely to be interested), we next examined
opportunities to reduce the overall development
and deployment schedule.

An Accelerated Deployment Paradigm
for Nuclear Energy Innovations
The traditional development and deployment
paradigm for commercializing nuclear energy
technologies is long and quite costly. Today,
both HTGRs and SFRs can proceed directly to acommercial offering based on the experience basethat already exists worldwide. (Plants involving
both technologies are already under construction
or operating in China and Russia.) However, for theless mature technologies (e.g., FHR, MSR, LFR, GFR),
we have outlined a different approach or strategy
that, by combining proof of concept and proof of
performance in a single full-scale machine, could
substantially accelerate the overall deployment
paradigm. This new approach comprises
three elements:• Develop a robust design for the reactor, withextra margins in thermo-mechanical terms sothat ASME stress allowables are not challenged,
to bound uncertainties in operation and safety,
as was done in the early days of LWRs.

• License the reactor using the NRC ‘prototype
rule.’ Prototype reactors have particularsignificance in NRC regulation. If a nuclear
reactor is constructed using designs that“differ significantly from light-water reactor
designs that were licensed before 1997, or use
simplified, inherent, passive, or other innovativemeans to accomplish their safety functions,”(U.S. Nuclear Regulatory Commission
2018a) the applicant must demonstrate thesafety of the plant using additional testing.
NRC regulations provide two avenues fordemonstrating safety:– Combination of analysis, appropriate test
programs, and operating experience; or– Operation of a prototype reactor undernormal and off-normal conditions.
If a prototype reactor is used to demonstratesafety “…the NRC may impose additional
requirements on siting, safety features, or
operational conditions for the prototype plant
to protect the public and the plant staff fromthe possible consequences of accidents during
the testing period” (NRC 2018b). The prototype
class of reactors (in its current form) was not
added to NRC regulation until 2007 (NRC2007). No applicant has pursued licensing ofa prototype reactor under this new rule andlittle NRC guidance exists on the process for
prototype reactor licensing. Based on feedback
from stakeholders on the topic of advanced
reactor licensing, NRC staff is currently drafting
white papers and more detailed guidance on
prototype reactors (NRC 2017).
• Locate the reactor at a site that features low
population density and a large site boundary
as an extra layer of safety and as a way toeffectively remove many safety constraints
on the design. This also allows the facility
to undergo a range of integral tests todemonstrate safety performance without
the need for additional safety systems.
Significantly reducing public safety concerns
in this manner allows for a less stringent
burden of proof and/or exemptions from somesafety regulations. For example, the computercodes used to design the plant do not haveto be completely validated, demonstrationsof passive safety features are not required
before the plant is built, inherent safety
demonstrations are conducted during theoperation of demonstration plants as has been
done with both HTGR and SFR technologies.
Examples of favorable sites include the Idaho
National Laboratory, Savannah River National
Laboratory, and Pacific Northwest National
Laboratory in the United States; the Cadarachesite in France; and the Canadian National
Laboratory in Canada. These locations havethe added benefit of having relevant power andnuclear infrastructure.
This strategy alters the traditional project risk
profile that has been associated with nuclear
technology development and deployment in thepast. Historically, overall project risk was reducedin the most cost-effective manner, which usuallymeant building the smallest possible machine
to retire early technical risk (associated withengineering demonstration for proof of concept).
That machine was then scaled up in size (and in
financial commitment) to address technical risks
associated with proof of performance. Altering
this overall project risk profile by combining theproof-of-concept and proof-of-performance
demonstration steps may enable acceleration of
the development and deployment timeline even
if it involves greater financial risk earlier in theprocess. Westinghouse has in fact proposed thisas a strategy for their lead-cooled fast reactor.
Historically, engineering demonstrations of early
reactor concepts were performed to demonstrate
proof of concept because there were so many
uncertainties associated with a new nuclear
concept involving new combinations of fuel,coolant, and moderator. Integrated system testing
was a necessary part of the process to prove boththe neutronic and thermal hydraulics aspects ofthe system and to provide valuable information to
reduce the technical risk associated with system
integration at this early stage. However, given thesimplicity of most new reactor designs and today’s
computational capabilities (Gaston, et al. 2015),
proof of concept could be established (andmuch of the technical risk could be removed)

Chapter 3: Advanced Reactor Technology Evaluation

89

Figure 3.7: Comparison of timelines under the traditional and proposed new development and deployment
paradigms for nuclear reactors
Timeline
5–8 YEARS

10–12 YEARS

10–12 YEARSDesign, License,
Build and Operate
Engineering
Demonstration

Design, License,
Build and Operate
Performance
Demonstration

Research andDevelopment

Traditional
Approach

Develop Design

Subsequent
Commercial Offerings

Establish
Supply Chain

Research andDevelopment

Proposed
New Paradigm

Develop Design
Establish
Supply Chain

Design, License,
Build and Operate
Performance
Demonstration
at Remote DOE
Site Using NRC
Prototype Rule

Subsequent
Commercial Offerings

Develop Integrated
Computational Models
18-GA50013-05

by using computation as a direct tool to shorten
the development cycle. Developing a computer
system to simulate the coupled response of thereactor (fuel, coolant, structure, balance of plant,
safety response) will be a significant challenge
but is clearly less costly than constructing an
extra demonstration facility. This approach is used
today in both jet engine design and automobile
development—for example, computational fluid
dynamics are used in lieu of conducting windtunnel tests on scale models and performance istested at full scale.
Finally, designing a performance demonstration
machine at full scale minimizes scale-up risk tovalidate/confirm computation simulations related
to proof of concept, and allows work toward theperformance demonstration objective to proceed
in a deliberate manner (including prudent power
ascension, tests of off-normal situations, andlonger-term operation to establish the reliability of
the integrated system).

90

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDIn principle, this strategy could apply to a reactor
of any size. However, it would not be attractivefor very large reactors (on the order of 1 GWe)
because of the enormous upfront cost of thedemonstration machine. At the other extreme,
microreactors (smaller than 10–25 MWe)inherently combine these two steps because thefinal reactor design is small enough to preclude theneed for an explicit scale-up step, which is a major
objective of the performance demonstration. For
reactors between these two extremes, whichis the size range of many of the low-maturity
small modular advanced reactors, this strategy
appears attractive.
This overall strategy does affect risks related
to supply chain development and component
integration. More work will have to occur in
non-nuclear test stands to qualify componentsthat are at or near full scale (either at vendor
facilities or in dedicated test loops) andcomponent integration risk will have to be deferred
until the full-scale performance demonstration canbe built and operated.

Figure 3.7 compares the traditional paradigm
and our proposed new paradigm for new reactor
technology development and deployment. The
new paradigm is more aggressive and entails
greater financial risk than the traditional approach.
However, if successful it could accelerate theoverall development and deployment scheduleby more than a decade, approximately, suchthat commercial offerings could be possible inthe mid- to late-2030s. If the new paradigm isnot successful, significant capital investment
losses could occur. Obviously even with anaccelerated strategy, detailed engineering anddesign work (on the order of millions of personhours) would need to be performed before
construction of an engineering/performance
demonstration machine could proceed. Financial
aspects of commercialization are discussed in
Chapter 4, which focuses on business models
and policy context.
Finding:

Recommendation:

A more innovative approach to deployment
is needed to advance less mature advanced
reactor designs. Under this new paradigm,
proof of concept and proof of performance
would be demonstrated using a single
reactor that would be: (a) designed atfull scale to reduce scale-up risks, (b)designed with conservative thermomechanical margins, (c) licensed under
the prototype rule developed by the U.S.
Nuclear Regulatory Commission (NRC) to
provide flexibility and reduce the burden of
proof typically expected in licensing, and(d) sited on a remote U.S. DOE site as an
extra precaution to remove some safety
constraints on the design and allow for
integral testing. Using this new paradigm,
development of the least mature systems
could be accelerated and the expected
timeframe for commercial deployment could
be moved up to the mid- to late-2030s.

Each advanced reactor system is at adifferent level of technical maturity and assuch requires a number of key technology
development activities to be completed
before it can be commercialized. The overall
time needed to reach commercialization
depends on the technical maturity of theconcept and prior experience with thespecific reactor technology involved. Moremature concepts, such as the advanced
small modular reactor (SMR) design
being marketed by NuScale, a sodium fast
reactor, and a modular high temperature
gas-cooled reactor, are technically readyfor commercialization by 2030. Less
mature reactor concepts, including lead
fast reactors, gas-cooled fast reactors, andmolten salt systems, would not be expected
to reach commercialization before 2050,
however, if the traditional approach tonuclear development is followed.

Chapter 3: Advanced Reactor Technology Evaluation

91

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94

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDChapter 4

Nuclear Industry Business Models
and Policies
This chapter discusses the actions that must be taken, by industry and government,in order for nuclear technology to continue making an important contribution to the global
supply of low-carbon electricity. Decarbonization is necessary to mitigate the risks posedby climate change but it will be difficult to achieve given the magnitude of global energy
demand and the scale of the infrastructure investments needed to transform existingenergy systems. Developing a wide array of low-carbon technology options, nuclear
among them, is vital to meeting this enormous challenge.

4.1 INTRODUCTION
As outlined in the earlier chapters, the major
obstacle for nuclear energy is cost. This holds
equally for the light water reactor (LWR)
technology used in most existing commercial
nuclear power plants, as well as for the various
advanced reactor technologies discussed in
Chapter 3. Government-supported R&D has
already helped advance some of the crosscutting
technology options discussed in Chapter 2.
Integrating these options into product design
and production processes to drive down costs isprimarily industry’s responsibility. Government
policies can assist industry by establishing better
frameworks within which companies can compete.
Both the rules that govern power markets andthe regulatory framework in which reactors arelicensed, sold, and operated have an important
influence on the economics of nuclear energy.
We outline three major areas for action. The firstis electricity market reform so that investors can
expect that competitive, cost-efficient nuclear
plants will be remunerated for the full value ofdelivering low-carbon electricity. The second
action area focuses on identifying sites anddeveloping accompanying services to enable
the accelerated deployment of certain advanced

reactors. The third action area involves support
for research, development, and demonstrationof advanced reactors.

4.2 ELECTRICITY MARKETREFORM AND REMUNERATION
OF LOW-CARBON ELECTRICITY
Chapters 1 and 2 showed that investments
in new nuclear power plants are uneconomical
in most circumstances under currently weakor non-existent carbon constraints. Reducing thecapital cost of new plants is essential if nuclear
energy is to remain a significant part of theoverall electricity generation mix in the future.
While plant cost is the primary issue, it is only one
part of the equation. The profitability of nuclear
investments also depends on how much revenue
they generate. Are investments in nuclear power
plants fully remunerated for the value of theelectricity they supply to the grid? At present,
the answer is clearly ‘no.’

Nuclear Power Plants in Crisis
A dramatic result of markets’ current underremuneration of nuclear-generated electricity has
been the recent closure, or announced closure,of several operating nuclear plants in the United

Chapter 4: Nuclear Industry Business Models and Policies

95

States before these plants reach the end of
their current licenses. These early retirements
are noteworthy, since the cost to construct thereactors is sunk. Even in a market where building
a new plant would be unprofitable, the continued
operation of a well-maintained and operated plantmight be expected to be profitable. A decision
to close means the wholesale price of electricity
does not even cover a plant’s ongoing operating
and maintenance costs, including any capital
investments needed to keep the facility in safe
working order. While the exact circumstances forthese decisions differ from plant to plant, a key
issue for many closed or endangered plants is low
profitability due to a very low wholesale price ofpower. Low wholesale prices, in turn, are driven
by the record low price of natural gas, among
other factors.1
For consumers and the broader economy, low-cost
natural gas has been a welcome development
because it means lower prices for electricity.
Cheap natural gas has also facilitated a solid firstincrement of reduction in U.S. electric sector
carbon emissions as natural gas-fired generation
has increasingly replaced coal-fired generation.
However, the simultaneous closure of existing
nuclear plants undercuts that success. Because
natural gas use still produces carbon emissions(albeit less than coal), nuclear plant closures
always mean that carbon reductions are smaller
than they could have been–indeed, in some cases
these plant closures have led to a measurable
increase in emissions.2 Also, nuclear plantclosures, by removing a non-carbon source fromthe resource mix, threaten the ability to achieve
future, deeper decarbonization targets, in the
United States and elsewhere.

Analyses of the cheapest ways to achieve
decarbonization point to the value of keeping
most of the existing nuclear reactor fleet operating.
For example, a study by Haratyk estimatesthat in the United States, nuclear plants with a
combined capacity of 20 gigawatts (GW) haveoperating deficits of less than $12 per megawatt
hour (MWh), which suggests that a credit of thisamount should be enough to keep these plants
open (Haratyk 2017). Twelve dollars per MWh isa low premium to pay for low-carbon electricity.
For example, it is much less than the cost of
current subsidies used to incentivize additional
wind generation.

Finding:

In most cases, existing nuclear is a costefficient provider of low-carbon electricity.
Premature closures of existing plants
undermine efforts to reduce carbon dioxide
and other power sector emissions andincrease the cost of achieving emission
reduction targets.

The fact that existing nuclear plants are acost-efficient source of low-carbon electricity
has recently become salient to authorities incertain U.S. states that are wrestling with exactly
how to achieve their increasingly ambitious
decarbonization targets. A few states, beginningwith New York, Illinois, and New Jersey, have
moved to provide some of the nuclear plants intheir states with supplemental credits in orderto keep the plants operating.

( Haratyk 2017) (Jenkins 2018) (U.S. Department of Energy 2017) However, a few closures were dictated byfactors other than simply low profitability. For example, public opposition is central to Entergy’s agreement toclose its Indian Point units which are located north of New York City. Also, in certain cases, although the power
plant was already built and long operating, it needed new capital investments in order to continue operating evento the end of the license. For example, Exelon’s Oyster Creek would have needed to make investments in new
cooling equipment.
2
In New England, carbon emissions had been gradually falling prior to the closure of the Vermont Yankee nuclear
plant and rose for the first time in the year after the closure. Similarly, when California closed the San Onofre
nuclear plant, a portion of the power was replaced with natural gas-fired generation, which increased emissions(Davis 2016). The agreement to close the Diablo Canyon nuclear recognizes that some of its power generation will
be replaced with natural gas-fired plants, again resulting in an increase in emissions.
196

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Policy makers in other countries have also
revisited the value of existing plants. In 2009, theSwedish government reversed course and choseto retain nuclear power in its generation mix inlight of the importance of taking action on climatechange (Regeringskansliet 2009). Similarly,
the French government recently postponed
previous commitments to reduce the share of
nuclear power in its generation mix. In contrast,
Germany’s decision to prioritize closing all of
its nuclear plants has made it difficult for thecountry to achieve its 2020 greenhouse gas
reduction targets.
Although many existing nuclear plants are acost-efficient option for low-carbon generation,
they are sometimes the least profitable option
for prospective investors because of the waythat policies for low-carbon generation are
structured. Instead of applying a uniform penalty
for carbon emissions, many countries haveadopted an amalgam of push and pull policies
that are designed to promote certain technologies
and discourage others. For example, several
U.S. states have introduced disincentives tocoal-fired generation on the basis of its carbon
emissions, but levy no comparable penalties
on natural gas-fired generation for its carbon
emissions. Similarly, policies such as feed-in
tariffs or renewable portfolio standards have been
established to reward wind and solar generation,
but these policies exclude nuclear, an equally
climate-friendly technology.
Figure 4.1 illustrates the situation for many nuclear
plants. The values in the figure are hypothetical,
though they are based on public reports for the
U.S. state of New York.
The bar on the left shows the $35/MWh total
market revenue earned by the nuclear plant.
This is less than the plant’s hypothetical operating
cost of $43/MWh, so the plant is unprofitable.
The second bar shows the market revenue for
a comparable fossil fuel-fired plant, which, bydefinition, is also $35/MWh. However, in thisexample, the fossil plant must pay a carbon
3

Figure 4.1: An illustrative example of how the missing
payment for nuclear energy’s low-carbon attributeaffects nuclear plant economics

charge of $6/MWh, so that the fossil plant’s
net revenue is $29/MWh. The full social cost ofcarbon, translated into emissions is $23/MWh,which is the third bar. The difference between thefull social cost of carbon and the carbon charge
levied is $17/MWh, which is shown in the fourthbar. If the nuclear plant were compensated forthis difference, it would earn a total of $52/MWhand be profitable.3
The shortfall illustrated here using numbers
scaled for the state of New York can be replicatedin many other contexts. The European Union’s
Emission Trading System (ETS) price for carbon
emissions is suppressed below what it would
otherwise be due to EU policies targeting only
renewables as a desirable low-carbon resource.
This produces a similar situation with respect tothe competitiveness of nuclear generation.

Finding:

A major source of revenue deficiency for
nuclear generators today is the fact thatthey are not fully compensated for their
low-carbon attributes. Ameliorating thisdeficiency would change nuclear energy’s
market position and conserve much existing
nuclear capacity.

 umbers for the existing carbon charge levied on the comparable fossil fuel-fired plant, for the social cost of carbon,
N
and the missing carbon value are based on material from the State of New York Public Service Commission (2016).

Chapter 4: Nuclear Industry Business Models and Policies

97

The majority of existing nuclear plants provide
a vital social benefit by delivering low-carbon
electricity in a reasonably cost-efficient way. To
avoid premature shutdowns and to incentivize
rational investments in extending the operating lifeof these plants, they should be fully remunerated
by electricity markets for the value of theirgeneration, including the social value of avoiding
carbon emissions.
Recommendation:

Public policies to advance low-carbon
generation should treat all technologies
comparably. There should be nodiscrimination against nuclear energy.
In principle, equal treatment of diverse
technologies could be implemented througha uniform carbon tax or through a universal
cap-and-trade system. Next best options include
broadening renewable portfolio standards or
auctions for the procurement of low-carbon
electricity to incorporate all low-carbon
technologies, including nuclear. Policy makers
should push in this direction. In practice, energy
and climate policies are an accumulation of
overlapping mandates, regulations, and taxes.
In this context, implementing the principle ofuniformity requires a broad appreciation of all thedifferent objectives that have shaped past policy
decisions, together with the exercise of reasonable
judgment. It is clear, however, that the current
system in many countries is far from the idealof uniformity and discourages cost-efficient
nuclear investments.

Competitive Electricity Markets
Some owners of nuclear power plants andother industry advocates complain that otherattributes of nuclear power are also inadequately
compensated, such as its contribution to gridstability, its ability to produce baseload power,
and its reliability and resiliency (Nuclear Energy
Institute 2015). They advocate changes to market
rules aimed at properly valuing these attributes.
498

Some critics expand this critique to a broader
indictment of competitive wholesale markets
generally. In 2017, the U.S. Department of Energy(DOE) proposed a radical change to the way many
nuclear and coal plants are remunerated: Under
the proposal, revenues for these plants would not
be determined in a competitive market but on a
cost-of-service regulated basis.4
While the details of electricity market design needscrutiny and improvement, market design failures
have not been a primary factor in the recent
closure of existing U.S. nuclear plants. Indeed, thecritique of wholesale markets implicit in the recent
U.S. DOE proposal seems designed to elude thesimple fact that nuclear power faces strong newcompetition as a provider of baseload power. In
the United States, most of the system benefits
advertised as unique to nuclear power can now be
provided by competing technologies at lower cost.
The decline in natural gas prices has made natural
gas combined cycle (NGCC) plants a lower-cost
alternative for providing baseload power in the
United States and around the globe. NGCC plants
provide most if not all of the additional attributes
that nuclear plants do, including grid stability.
It is true that NGCC plants depend on the reliable
delivery of natural gas, and that fuel availability
varies by region and country. Consequently, there
can be specific locations where an NGCC plantcannot provide the same reliable capacity or thesame resiliency. But in many U.S. regions, natural
gas supplies are readily available, so that NGCC
plants are able to provide the same services andat a lower cost. Reliability also depends on market
structure and on the contract terms that govern
natural gas supplies to a given NGCC plant.
Thus, there may be specific NGCC plants withgas supply contract terms that do not provide
the same reliable capacity. However, these market
structures and contracting terms can be modified
and in key U.S. markets where reliability of fuelsupply was a concern, adaptations have beenmade. The bottom line is that falling natural gas
prices have driven down the value of all generation
attributes provided by nuclear power plants except
one: avoided carbon emissions.

 he proposal was ultimately rejected by the Federal Energy Regulatory Commission, which decided instead toTfurther investigate the issue of resilience as experienced in different electricity markets (U.S. DOE 2017a).

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDIn addition, certain attributes highlighted by
nuclear energy advocates, such as grid stability,
do not currently have high value because
low-cost sources of these services are plentiful
relative to the need. Contributions to gridstability, for example, come in many forms.
Most thermal generators that drive steam
turbines provide valuable inertia to the systemand thereby automatically contribute to frequency
stabilization. Some generators allocate a portionof their capacity to provide regulation services.
The current market value of inertia is effectively
zero on most systems since the number ofturbines is so large relative to the need for inertia.
The market price of regulation service is morethan zero, but trivial in the overall scheme of thewholesale market. In 2016, in the market served
by PJM, a large grid operator in the northeasternand mid-Atlantic region of the United States,
total charges for many different ancillary services
provided to the grid amounted to less than 2% of
the average hourly wholesale price (Monitoring
Analytics 2016). This could change and ancillary
services could become more valuable if markets
are eventually dominated by renewable generatorsthat provide no inertia and frequency regulation
at all, but a conjectured future has little to dowith the nuclear industry’s revenue problems
today. Indeed, renewable energy technologies
have been evolving, and system codes are being
adapted so that new wind and solar installations
are increasingly able to provide some fast-acting
reserves that contribute to grid stability.
Finding:

There is little evidence that revenue
deficiencies for existing nuclear power plants
in the United States are due to ‘attributes’
that are being systematically mispriced bywholesale electricity market rules, aside
from the failure to properly price nuclear
energy’s climate benefits.

Where nuclear is significantly undervalued, thesource of the problem is not the rules of themarket per se, but rather broader public policies
regarding renewables and nuclear. These policies

shape market outcomes, but it is incorrect toblame the market. The schematic in Figure 4.2
helps make the point that the revenue earned bya nuclear power plant—or by any power plant—
is determined by wholesale market pricing rules,
and also by a variety of other policies outside thewholesale market.
Figure 4.2: Electricity wholesale market pricing
rules combine with the larger regulatory framework
to determine the profitability of different
generation technologies

A concrete example is the federal production
tax credit paid to wind generators in the UnitedStates. This is an out-of-market payment that
supplements what the wind generator receives
from the competitive electricity market. The factthat the wind generator receives an out-of-market
payment influences the generator’s operating
decisions and thereby affects the market price.
This is most transparently seen on the occasions
when the market price becomes negative, which
can occur when the wind resource is plentiful attimes of low load. The wind generator is willingto continue operating at a negative price because
it can capture the federal tax credit only byputting power onto the grid (U.S. DOE 2017b).
While the rare occasions when wind generators
operate at a negative price represent an extreme
case, it is more generally true that the out-ofmarket payment lowers the average competitive
wholesale price of electricity. It creates adifferential between the per-unit revenue earned
by a nuclear generator and a wind generator

Chapter 4: Nuclear Industry Business Models and Policies

99

operating in the same location and delivering
the same power. Where the nuclear generator
earns only the market price, the wind generator
earns the market price plus the out-of-market
payment, potentially leading to investments in
new renewable generation and simultaneous
retirements of existing nuclear capacity.
In the United States and elsewhere, public
policies operating outside the narrow rules of
the wholesale market are creating incentives for
low-carbon generation in a discriminatory fashionthat is designed to benefit some low-carbon
technologies but not others. These policies
operate in conjunction with market rules, but themarket rules themselves are not discriminatory.
(FERC 2017) On the contrary, public policies
are often designed to achieve a particularoutcome that the market alone, operating in a
non-discriminatory fashion, would not deliver.
No amount of tinkering with market rules will
make nuclear energy more competitive so long as
public policies prefer one low-carbon technology
over another. In Germany, where the government
has adopted a plain mandate to force the closureof nuclear plants, market rules are irrelevant.
In other countries, like the United States, public
attitudes and policies toward nuclear energy areless unambiguously negative, but policies thatfavor renewables over nuclear remain a root causeof the industry’s revenue problems. The U.S. stateof New York provides another example of how
public views and political considerations canshape policies and override markets. In an effort
to preserve a pair of existing nuclear plants,
New York proposed to extend to these plants thesame low-carbon incentives that it provides torenewables. However, the Indian Point nuclear
plant was specifically excluded from this policy
because powerful political interests oppose
the continued operation of a plant so close to
New York City. This differential treatment of the
upstate plant relative to downstate plants had
nothing to do with how the competitive wholesale
electricity market functions and everything to dowith the inescapable fact that public attitudes,
as expressed through political decisions, drive
ultimate outcomes.

100

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Finding:

Discrimination against nuclear as a
low-carbon energy source is not rooted
in technical issues of electricity market
design. Rather, it is primarily rooted in public
attitudes towards nuclear. These public
attitudes translate into discriminatory public
policies outside of wholesale market rules,
which in turn shape profitability.

Nonetheless, it remains important to regularly
revisit the issue of electricity market design as
public authorities have done for the past few
decades. A well-designed market is shaped by
the profile of the technologies that are in themarket. As more renewables have moved onto
the system in recent decades, market rules andpractices have gradually adapted to incorporate
and shape these new technologies, too. Progress
toward the deep decarbonization of the electric
power sector worldwide will bring an even moresignificant shift in the profile of technologies
on the grid, including an expanded role forrenewables and greater reliance on energy storage
and demand response, among other changes.
Further modifications to market design may beneeded to respond to these changes.
In particular, a shift away from fossil fuel-fired
generation, which has significant variable
operating costs, toward low-carbon technologies
like renewables and nuclear, which have low orzero variable operating costs, could further reduce
the share of revenues earned in the energy market
and increase the importance of the capacity
market. In that case, continuing improvementsin the design and operation of capacity markets
will be important (Seel 2018).

Recommendation:

Achieving deep reductions in global
carbon emissions will require a dramatic
restructuring of the technologies deployedin the electricity industry. Constantadjustments will be needed to alignmarket rules to the new technologies
being deployed. The nuclear energy
industry has a stake in ongoing research toassure that changes in market design are
consistent with the deployment of advanced
nuclear systems.

Policy Support for Cost-Efficient Nuclear
Energy Technology
Changing the revenue side of the equation for
nuclear generators through uniform carbon
policies is not just relevant for existing plants. It isalso necessary to properly incentivize innovations
in nuclear energy technology and investments
in future new builds of nuclear plants whereappropriate. Investors pursuing new, truly low-costnuclear designs must see the possibility of earninga fair profit based on selling their products for theirfull value, including the social value of providing
low-carbon generation. Current policies that
disregard the social value of nuclear energy’s
contribution to climate change mitigation reduce
the prospect for profit and discourage investments
in nuclear innovation.
Alongside uniform carbon policies, following
through on a number of other enabling actions
is important to demonstrate to potential private
investors that nuclear energy has a future.
For example, in the United States, the federal
government’s decades-long failure to implementa coherent nuclear waste policy has created a
cloud hanging over investments in new advanced
reactors. Although the U.S. Congress ostensibly
settled on a waste management policy by passing
the Nuclear Waste Policy Act Amendments in
1987, from a practical perspective U.S. policy is in
disarray. The process to license a deep geologicalrepository for the permanent disposal of spent
nuclear fuel at Yucca Mountain in Nevada has
been started and then stopped. The current

Trump administration has stated its intention
to get on with licensing efforts again, but it issure to face opposition and its intention has
not been accompanied by any political plan for
winning over opponents of a repository at Yucca
Mountain. Establishing a politically durable waste
policy—by which we mean a policy that has
the broad political support to continue throughchanges of administration and Congress—would
be helpful to encourage investment in new reactor
designs. Garnering the buy-in needed to construct
such a durable policy is extremely difficult in
the current era, but it is nevertheless critical for
future investment flows. One option that has
some support (Kazimi, et al. 2011) (Blue Ribbon
Commission on America’s Nuclear Future 2011)
would be to pursue a consent-based approach tositing, perhaps starting with local communities
in places such as New Mexico and Texas thathave expressed interest in potentially hosting arepository (Bryant 2017).
Some other countries have made notable progresson the waste management issue. In particular,
Finland has successfully sited its Onkalo spent
nuclear fuel repository and has begun construction(Fountain 2017). Sweden’s process for developing
a repository is also moving forward (Plumer 2012).
Recommendation:

The implementation of a politically
durable solution for the managementof spent nuclear fuel would greatly
facilitate significant investment in new
nuclear technologies.

4.3 ENABLING NUCLEAR INNOVATIONThe current moment brings significant opportunity
for the nuclear energy industry. The need for
low-carbon electricity is enormous and likely togrow in the near future. As detailed in Chapter 3,
the industry is developing a wide range ofadvanced reactor concepts, in addition to thefamiliar light water reactor. While many of theseconcepts have been around since the dawn of
the nuclear age—indeed, several were tested

Chapter 4: Nuclear Industry Business Models and Policies

101and demonstrated long ago—improvements
in associated technologies, such as thedevelopment of new materials and analytic
tools, make practical today what was impracticalyesterday. The challenge is to translate theseconcepts into plant designs that can produce
cheap, grid-connected, low-carbon electricity.

The Changing Global Market
The global marketplace for nuclear power plants
is changing rapidly, on both the demand and the
supply sides. Economic development in non-OECD
countries is rapidly shifting the center of gravity
for global electricity demand, and interest in
new nuclear plant investments, too. The largest
numbers of new reactors under construction are
in China, India, Russia, Korea, and the United ArabEmirates. The United States and France still havethe largest and second-largest fleets of operating
reactors, respectively, but China will soon
overtake France. In the U.S. Energy Information
Administration’s International Energy Outlook
2017 ‘Reference Scenario,’ net nuclear generationin the OECD countries is projected to be flat orslightly declining through 2050. By contrast, net
nuclear generation in the non-OECD countries
is projected to increase nearly four–fold over thesame timeframe. As a result, nuclear generation in
non-OECD countries equals generation in the OECDby 2038 and then grows beyond it, according to
the U.S. Energy Information Administration (EIA)
projections. For companies that are developing
energy technologies and products for export, it isimportant to have in mind the increasing diversityof the international marketplace. In particular,
while some countries will make decarbonizing
the electricity sector a top priority, others willprioritize expanding access to energy. This meansthat nuclear generation options will be comparedagainst other low-carbon technologies in somecountries, and against fossil fuel technologies

5102

in others. To capture a larger market worldwide,
it will be even more imperative for the nuclear
energy industry to radically reduce costs.
The home base for reactor vendors is shifting also.
Until recently, the United States, Western Europe,
and Japan had been the major global exporters ofcivilian nuclear energy technology and expertise.
Now there are additional players. Russia, buildingon the legacy Soviet industry, is advancing
nuclear energy as a major export industry. Korea
has become a competitive exporter, and China
is preparing to become one. The global export
market for nuclear technology is therefore much
more competitive.
For example, the state-owned Korea ElectricPower Company (KEPCO) developed theGeneration-III+ Advanced Power Reactor 1400
(APR1400) by building on the success of its
construction program for the Generation-II
Optimum Power Reactor (OPR). The first buildof an APR1400 was completed in 2016 at thedomestic Shin-Kori 3 unit. In 2009, KEPCO
won a competitive bidding process to provide
four reactors of this design to the United ArabEmirates at that county’s Barakah site, with
Hyundai as the engineering, procurement, andconstruction (EPC) contractor. The first unit
will soon be operational. The reported price forthe reactors is $3,457 per kilowatt of electricalgenerating capacity (kWe). It is difficult to be surewhat is included in this number,5 but the figure
represents an important data point given KEPCO’s
design success and Hyundai’s construction
experience in the Emirates, and their ability to
win the Barakah tender.
The Russian state-owned company Rosatom has
continued its line of Vodo-Vodyanoi Energetichesky
Reactors (VVER) with the Gen III+ VVER-1200,
also known as the AES-2006 (Goldberg andRosner 2011). The first reactor of this design went
into commercial operation in 2017 as Unit 1 at the EPCO, December 2016, Investor Presentation, reports a total cost of $18.6 billion. Dividing this by the total
K5,380 GW capacity of the 4 units yields the $3,457/kW figure. The presentation provides no detail about what isincluded in this figure or the quotation convention. For example, it probably excludes owners’ costs which could
add another 20% in order to be comparable to other figures. Press reports variously report the deal to be worth$20 billion, $25 billion, $30 billion, or even $40 billion. This latter figure is from the Korea Herald, June 20, 2015.
For a detailed analysis of KEPCO’s bid, see Berthélemy (2011).

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Novovoronezh II plant, and a second is currently
under construction at the same site. Two units
are also under construction at the Leningrad II
plant. In addition, construction has begun on thefirst unit at the Kaliningrad or Baltic plant. Russia
considers its AES-2006 design to be a valuable
export product. Construction on the first two units
to be built outside Russia began in 2013 and 2014
at the Ostrovets site in Belarus; construction on
another unit began in 2017 at the Rooppur site
in Bangladesh. Russia also has an agreementwith Turkey to build four units at the Akkuyu site,
although the ownership structure for this projectis unsettled at the moment. Rosatom has anagreement with Hungary for two units at the Paks
site, an agreement with Finland for one unit at theHanhikivi site, and an agreement with Egypt for
four units at El Dabaa. Which of these projects will
be realized, and how quickly, is unclear.
The Akkuyu agreement is notable for Russia’s
use of a build–own–operate model to advanceits exports. In this model, the buyer is relievedof a significant amount of risk. But Russia istaking this approach a step further: in addition
to supplying the fuel for Akkuyu, Rosatom
is said to be taking back the spent fuel for
reprocessing. The final disposition of waste
destined for a repository is unclear.
Of all countries currently investing in nuclear
energy, China has the largest number of newreactors under construction. Many of theseare designs exported to China from a diverse
set of companies and countries. The Chinese
have also been developing their own designs.
Of particular note for the global marketplace is a
joint venture of the China General Nuclear PowerGroup (CGN) and the China National Nuclear
Corporation (CNNC) to develop the Generation-III
Hualong One (HPR1000) reactor. The first
domestic units using this design are underconstruction at Fuqing 5 and 6 and Fangchenggang
3 and 4, and more are planned. Two HPR1000
reactors are under construction at Karachi Nuclear
Power Plant (Kanupp) in Pakistan. CGN–CNNC
has an agreement for a build in Argentina andis exploring a build in the United Kingdom
at the Bradwell site.

Development of advanced reactor concepts is
proceeding globally, too. The United States has arich legacy of experimentation and demonstrationin this domain. Several U.S. companies havedesigns built on that experience, and the U.S.
government continues a small R&D programin support of continued reactor development.
Many countries have experience operating fast
reactors, led today by Russia and including France
and the United States. China is currently building
a demonstration high temperature gas-cooled
reactor (HTGR) and is experimenting with otherconcepts. Companies exploring new designs are
based in various countries.
Dramatic shifts in who is buying and who isoffering commercial nuclear reactor technology
will undoubtedly reshape the structure of the
global marketplace for this energy source.
In an earlier era, the United States played an
important leadership role for the global nuclear
energy industry, both in its role as a supplier oftechnology and because of its outsized share ofoperating nuclear power plants. As a result, U.S.
influence shaped licensing and safety standards
as well as anti-proliferation protocols worldwide.
In the current era, global practice will evolve in
response to multiple players. Domestic policies
to enable nuclear innovation sit inside this larger
global context.

Commercially Driven Innovation
In the past, governments often directed thedevelopment of new reactor designs. This included
the early development of the pressurized water
reactor for naval propulsion, which was leveraged
into commercialized LWR designs for power
generation. In pursuit of fuel security, governments
have also pushed forward breeder reactor designs
and, more recently, high temperature reactors.
Individual nations may still see a valuable rolefor specific government-directed programs.
However, we believe that the specific challenge
of developing and deploying a new generationof nuclear technologies as part of a global effort
to achieve deep carbon reductions can be best
met with a shift away from government-directed
programs towards commercially driven innovation.

Chapter 4: Nuclear Industry Business Models and Policies

103

The public interest in affordable low-carbon
electricity can potentially be fulfilled by a varietyof reactor designs, and, except in special cases,
there is little public interest in favoring one designor another at the outset. The public interest isin enabling competition among designs. Exactly
which concept is most suited to exploiting costsaving technologies, such as those discussed
in Chapter 2 or others, is something that can
only be determined through continued R&D, by
actually building demonstration reactors, and by
producing plants. The task is to select from anarray of possible designs those technology choicesthat are most likely to lead to a low-cost power
plant, and then to carefully manage and ‘ride
herd on’ the testing and development process as
it moves toward deployment. This is exactly thetype of innovation process that private industry
manages well, that competition promotes, andthat governments should enable. Great value canbe gained from harnessing commercial interests
to select among technology options and drive
key technology choices through development
and deployment.
As discussed in Chapter 3 as well as in thenext section, the resources required to bringnew designs to market are very large and thetime horizons are long. There will be a needfor government support, and with government
support must come public accountability.
Nevertheless, accountability to overall project
goals can be built in without the government
directing specific technology choices.
Governments around the world have been andshould continue to be important funders of basic
research. Indeed, most of the advanced reactor
concepts being considered today were developedin various government-funded programs, as weremany of the crosscutting technology options wehave identified as holding promise for reducing
costs. The next section returns to the role of publicfunding in advancing basic science. However, thefurther development of different reactor concepts
and the integration of various related technology
options is a different enterprise. Therefore, we
also outline specific actions to enable innovation
driven by industry.

104

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Finding:

Private business is well suited to driving
innovations that would lead to new reactor
designs with radically lower capital costs.
To harness this capability, the private sector
must make the technology choices andsupply the major capital investments. Privatecompanies must enjoy the potential for
profit and also bear the risk of loss.

The type of shift we are proposing here, fromgovernment-directed to commercially-directed
technology development, has occurred in otherfields. A recent notable example is the Commercial
Orbital Transportation Services (COTS) programin the United States, which was established by the
National Aeronautics and Space Administration(NASA) in 2005 (Lovering, King, and Nordhaus2017). COTS was designed to encourage theemergence of a U.S.-based spaceflight industry
managed by the private sector. The idea wasthat NASA, instead of purchasing space vehicles
through cost-plus contracts, would incentivize
companies to develop and own their own
equipment. NASA would then purchase thesecompanies’ products and services as needed(National Aeronautics and Space Administration2014). NASA defined a set of mission capabilities
but left it to private companies to decide how best
to design and build equipment to provide thesecapabilities. To help companies get started andbegin developing capacity, NASA would make anearly financial commitment, but companies would
also have to prove their commercial viability byraising their own capital as well.
NASA solicited proposals and by August 2006,
it had signed agreements with two companies:
SpaceX and Rocketplane-Kistler (RpK). The
agreements defined a sequence of intermediate
milestones towards the final mission capability;
under the agreements, the companies would get afixed payment from NASA for reaching each of themilestones. Eventually, the agreement with RpK
was abandoned when the company failed to raise
the promised outside financial investments needed
to continue; NASA then put out a second-roundsolicitation and awarded an agreement toOrbital Sciences Corp. Although responsibility
for execution remained with the companies, therelationship was a cooperative one. For example,
the companies occasionally took advantageof NASA subject matter experts to help tackle
difficult technical problems, and NASA provided
the sites from which the commercial vehicles
were launched. By 2012 and 2013, both SpaceX
and Orbital had completed demonstrations of
their mission capability as defined under theiragreements with NASA. Both companies are now
vendors to NASA, providing resupply services tothe International Space Station under contracts
that are awarded through a competitive process.
The U.S. DOE also has experience with this typeof public-private cooperation. Most recently,
DOE established its Gateway for Accelerated
Innovation in Nuclear (GAIN) program. Throughthis program, commercial nuclear companies canbe awarded vouchers that enable them to makeuse of federal laboratory facilities and staff as they
pursue technical research on fuels, materials, andother issues that will help advance reactor designs.
The urgency of the climate problem and the needfor dramatic progress toward decarbonization
argue for government efforts to enable theaccelerated technology development pathway
discussed in Chapter 3. That pathway shortens
the time for demonstration by identifying asite where a prototype reactor can be built andtested under appropriate safety regulations.
Government owned, operated, and supervised
sites still offer the best settings to assure public
safety and continue government engagementwith testing. Such sites should be made available
to demonstrate properly vetted commercial
reactor prototypes. In addition to its interestin safe testing, the government’s vital interestin the fuel cycle necessitates its involvementin the production of new fuels and in the safe
management and disposal of wastes.
The Canadian Nuclear Laboratories (CNL)
recently proposed an initiative that would
allow its facilities to be utilized in cooperation
with private companies to “demonstrate thecommercial viability of the small modular reactor
by 2026” (Canadian Nuclear Laboratories
2017a) . CNL intends to host a demonstrationor prototype reactor and recently published a‘Request for Expressions of Interest’ to seek
feedback from industry and stakeholders on how
to structure a successful program. It has received
80 submissions and 19 expressions of interest
from technology developers (Canadian Nuclear
Laboratories 2017b). CNL has stated that it is open
to hosting multiple prototype reactors and reactor
types, subject to its own support capabilities(Nuclear Energy Insider 2017). CNL is already inthe midst of a major capital investment programat its Chalk River site; initial actions undertaken as
part of its small modular reactor (SMR) initiative
should help CNL identify what new facilities aremost needed for this mission (Atomic Energyof Canada Limited and Canadian Nuclear
Laboratories 2017).
Recommendation:

Governments should establish reactor parks
where companies can site prototype reactors
to conduct testing and operations oriented
to licensing. These parks should be open
to diverse reactor concepts chosen by thecompanies. Governments should provide
appropriate supervision and support—
including safety protocols, infrastructure,environmental approvals, and fuel cycle
services—and should be directly involved
with all testing.

Participation in this type of initiative should bedetermined via an open solicitation that allows
for a wide variety of reactor types and designs.
Choice of the reactor design would be up to thesponsoring company, subject to establishedsafety protocols and to the government’s ability toprovide needed support obligations. The company
would be responsible for constructing the reactor
and would have to demonstrate the appropriate
financial capability. The government would workwith the company to procure the fuel feedstockneeded to test and operate the reactor and would
act as the agent for handling spent fuel and other

Chapter 4: Nuclear Industry Business Models and Policies

105

hazardous materials. The agreement would
enable sale of the power onto the grid throughnormal commercial channels, consistent withgrid protocols. It would also make provisions forthe disposition of the prototype reactor, including
eventual dismantling at company expense once
testing and operation for reactor licensing haveconcluded and, in some cases, after further
operation on a commercial basis consistent withthe site’s safety requirements.
Establishing reactor parks with the necessary
infrastructure will require direct funding to handle
expenses incurred by the government outside
the construction and operation of prototype
reactors. Mechanisms for charging fees to reactor
park users can be established, but some direct,
additional funding would have to be provided.
This is appropriate in light of the government’s
interest in various aspects of the innovation
process and in developing and maintaining its own
capabilities by means of its participation.

4.4 PUBLIC SUPPORT FOR
RD&D ON ADVANCED NUCLEARTECHNOLOGIESThis section discusses how governments
can support research, development, anddemonstration (RD&D) on advanced nuclear
technologies. The focus here is on advanced
reactor concepts that have not yet been
demonstrated. We do not discuss RD&D
on established LWR technology.

Cost and Time for a Technology
Development Project
The complete process of bringing a reactor
concept to commercial deployment involves
many expensive steps, including further R&D, fulldetailed engineering design work, developmentof fuel and provisions for spent fuel disposition,
construction and testing of a prototype, andlicensing. The cost of completing this process willvary based on the reactor design. A number ofstudies in recent years have estimated these costs
for particular designs. Several of these studies were
produced in connection with the U.S. government’s
interest in developing HTGR technology, which

106

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDculminated in the Next Generation Nuclear Plant(NGNP) program (Idaho National Laboratory2007) (U.S. Government Accountability Office2014) (U.S. Department of Energy 2010) (NGNP
Industry Alliance 2015). All of them projectedcumulative costs in the neighborhood of $4 billion
to construct the first full-scale plant. This figure
does not include up-front R&D and design costs,
which could run up to $1 billion. Commercialization
would also incur additional costs for post-design
licensing related to developing a supply chain
for fuel and other equipment, as well as extra
shakeout costs on the first new builds. These
could also easily run in the neighborhood of$1 billion, bringing the total cost of thedevelopment program to more than $6 billion.
A later study by several DOE national laboratories
detailed additional costs for less mature designs(Argonne National Laboratory, Idaho National
Laboratory, Oak Ridge National Laboratory 2017)(Petti, et al. 2017). A recent DOE Task Force Report
included a mid-range estimate of $11.5 billion for
the total cost of implementing a generic programthat would take two reactor designs throughthe demonstration phase and bring one design
to construction of a first-of-a-kind commercial
reactor. This estimate included pre-demonstration
costs, the cost of two demonstration reactors,
and the cost to build a first-of-a-kind commercial
reactor (U.S. DOE 2016). The time horizon
between the up-front investment and the datewhen the first commercial returns begin to arrive
is quite long.
To illustrate the potential time and cost involvedin a major technology development project, weconstructed a pair of hypothetical examples
based on the sources mentioned above. One is atechnology with high maturity, so, in accordancewith the discussion in Chapter 3, after some
additional work on design and licensing, andinvestments in supply chains, it can go directly
to a commercial demonstration. The second isa technology with lower maturity. In accordancewith the accelerated development paradigm
proposed in Chapter 3, it requires additional
preliminary R&D and design work, and aperformance demonstration reactor before going
to commercial demonstration.

Table 4.1: Input values for illustrative examples of required costs for two alternative advanced
reactor development projects

Performance Demonstration

Early
Development

Higher Maturity
Technology
Years
Expenses, $ million

Years

3

8

R&D

50

300

Design Development

100

200

Supply Chain

100

200

Pre-build

2

Build

7

Operational Testing
Plant

Expenses, $ million

5

Capacity, MWe250

Unit cost, $/kW

9,200

Design Completion

300

Licensing

200

Construction

2,300

Operational Testing
Commercial Demonstration

Pre-build
Years

Plant

Expenses, $ million

Lower Maturity
Technology

400
2

2

Build

5

5

Operational Testing2

2

Capacity, MWe

250

250

Unit cost, $/kW

6,900

7,100

Design Completion

100

100

Licensing

200

100

Construction

1,725

1,775

Operational Testing

200

200

2,475

6,075

Total Expense of Development

The values in Table 4.1 are all real or constant dollars. In Figure 4.3 the values are nominaland so reflect a 2% inflation rate.

Our assumptions with respect to timing and costfor both development projects are detailed inTable 4.1. The cumulative cost for each projectthrough completion of the first demonstration
reactor and its initial operation and testing areshown as the orange lines in Figures 4.3 and 4.4.
The x-axis of each figure shows the stages of thedevelopment process. Figure 4.3 shows that thehigh maturity technology requires three years ofearly development. It also requires final design
work and licensing, which happen at the sametime in years two and three. Then the commercial
demonstration reactor is constructed over a
period of seven years. Finally, the commercial
demonstration reactor requires two years ofoperational testing before the development
project is complete at the end of twelve years.
Figure 4.4 shows that the low maturity technology
requires eight years of early development. It also

requires final design work and licensing, whichhappen contemporaneously in years seven andeight. Then the performance demonstration
reactor is constructed over a period of sevenyears. Five years of operational testing are thenrequired before the performance demonstration
stage of the development project is completeat the end of twenty years. At that point, thelow maturity technology is ready to progress
to commercial demonstration.
The two figures make a powerful point about
the size of the investment and the length of timerequired before a new technology can begin
earning revenue. The two figures also show the
impact of government funding, as discussed in
more detail later in this section.

Chapter 4: Nuclear Industry Business Models and Policies

107Figure 4.3: Illustrative example of cumulative total cost and net investor cost for a high maturity technology

Figure 4.4: Illustrative example of cumulative total cost and net investor cost for a low maturity technology

future&produc2on&credits&
valued&=&$642&m.&

govt&funding&=&$1,308&m.&

early&development&

construct&performance&demo&

opera2on,&tes2ng&and&licensing&

NOAK Deployment (2ndcomm. +)

Table 4.2: Input values for illustrative examples of sources of earnings for two advanced reactor
development projects

108

Plant

Build rate
Design fee

Higher Maturity
Technology

Lower Maturity
Technology

Capacity, MWe

250

250

Unit cost, $/kW

4,600

4,600

Expense, real $million

1,150

1,150

4

4

$/kW

920

920

% overnight cost

20%

20%

Years @ 4/yr,
thereafter @ 8/yr

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Table 4.2 summarizes our assumptions about
how each development project will earn a return.
It details the projected cost of a NOAK plant anda build rate. The development project earns a
return during the build-out phase through profits
earned on selling its plants and providing various
associated technical services. We represent theseearnings as a design fee paid for each plant built.
Figures 4.5 and 4.6 show the time scale required
for each development project to recoup its
investment—i.e., the payback period. How quickly
this happens will depend on the demand foreach design, and on how quickly it can scale up
production. The orange line shows the total valueof cash invested, net of receipts, through any given
date. Note that the total goes to nearly -$5 billion,
which is far below the $2.5 billion sum that wasinvested at the conclusion of the development
project. That is because this figure also includes
the return required on invested capital. (The uptickin the curves around years 12 to 13 is due to the
production credits paid to the demonstration
plant. The curve then decreases as the subsequent
plants are built.)
At the conclusion of the development project,
the investment can begin to earn a return fromthe deployment of subsequent plants. The grossinvestments needed to build subsequent plants
and the payments received for those plants are notshown here. Instead, to focus on the return to thedevelopment project, the calculation shows thedeveloper receiving a royalty on the plant designfor each subsequent plant built. Constructionof the next four plants is assumed to begin
immediately at the conclusion of the development
project and to take five years. Once the first fourcommercial-scale reactors come on line in year 18,
another four come on line in each successive year
until year 22 when the rate doubles to eight plants
each year. In the figure, the orange line becomes
positive in year 21—when the investment in thedevelopment project has been recouped.
The low maturity technology requires a much deeper
investment. At the conclusion of the performance
demonstration in year 20, the first commercial
demonstration reactor remains to be built. Only
once that is complete can a full-scale build out

Figure 4.5: Time to recoup investment in development
project for high maturity technology

Figure 4.6: Time to recoup investment in development
project for low maturity technology

begin. The orange line shows the total value of cash
invested net of receipts through any given date.
Note that the total goes to nearly -$40 billion,
which is far below the $6 billion sum that wasinvested at the conclusion of the development
project. As the figure shows, the total investment
cost is not recouped until sometime after year 41.
The two figures also show how government
support affects investor returns for the two
hypothetical technologies.

Government Support for Technology
Development
Governments are a valuable and often essential
partner in funding RD&D for new technologies.
This is true for nuclear as well as for other energy
technology options, such as photovoltaics,

Chapter 4: Nuclear Industry Business Models and Policies

109batteries, and so on. Historically, government
support has made it possible to ready numerous
important technologies for commercial
deployment. The urgent public need for a suiteof low-carbon generation options warrants asizable investment. It is impossible today to
say with any confidence exactly how or when
the goal of decarbonizing the electricity sector
might be achieved. In fact, the uncertainties
and contingencies are so great that it would be
imprudent to count on any single technology or
technology path. In the face of great uncertainty,
the option value of having multiple low-carbon
energy alternatives is enormous. To develop
those options requires funding many possible
technologies. In sum, we need more shots on goal.
Government support for the demonstration ofnew, advanced reactor concepts is also essential
for attracting and making feasible the scaleof private investment shown in our examples.
Reactor developers and governments are
inescapable partners to some degree. No matter
how promising or potentially cost-effective it
is, a new reactor design can only go to market
with the benefit of government cooperation ona range of issues. Given the size of the upfront
investment required and the long time horizon
before investors can expect to see any returns,
government buy-in to the development process
will be extremely important to private investors.
We do not advocate government funding for theongoing commercial deployment of any specificlow-carbon generation technology, whether
nuclear or any other, beyond its initial launch.
The structure through which government support
is channeled is important to maximize the likely
success and impact of public funding. As wehave already emphasized, we believe commercial
interests should make key choices among
competing reactor concepts and should guidethe detailed implementation of any design. That
will require that companies put their own capitalat risk and enjoy both the prospect of profit andpossibility of loss. The public’s interest is in thedevelopment of any options that will successfully
deliver a product. The funding program weare proposing for U.S. government support ofadvanced nuclear technologies is structured

110

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDaccordingly; it also draws on several existing U.S.
funding channels and program experiences. This
framework can be applied by any government thatseeks to implement advanced nuclear technology.
First, there is a need for specific R&D funding
to bring some advanced reactor designs to thepoint of readiness for demonstration. The U.S.
DOE already plays a vital role in funding R&D, at
its own labs, at universities, and in collaboration
with businesses. Expanded funding targetedto advanced reactor designs is appropriate,
and appropriate avenues for delivering thisfunding can be created using models such as
the GAIN program.
Second, funding is needed to facilitate thelicensing of new reactor designs. The next chapter
discusses funds that the U.S. Nuclear Regulatory
Commission (NRC) has dedicated to develop its
capability to license advanced reactors. Here wehighlight the need for funding to help share thelicensing costs incurred by reactor developers forthe first advanced reactor designs. DOE employed
this sort of cooperative arrangement in its NP2010
program, which was established to support thelicensing process for new reactors under the
Energy Policy Act of 2002 (U.S. DOE 2012).
In addition to funding for R&D and licensing, we
advocate a third and fourth lever for supporting
the large capital investments that will haveto be made up-front by private investors.
These are milestone payments for prototype
reactors and production credits for energy
delivered from the first reactors.
Milestone payments were a feature of NASA’s
COTS program. Under that program, theagreements NASA negotiated with individualcompanies included a suite of intermediate
milestones towards the final demonstrationof mission capability. Accomplishing eachmilestone triggered pre-specified payments fromNASA to the companies. Individual milestone
payments ranged in size from $4 million to$31 million, with the program paying out about$780 million in total. For the two companies
that successfully participated in COTS, thesepayments recouped slightly less than half the total
development costs they incurred to demonstratemission capability (NASA 2014). The other halfof the costs represents the net investment by
the companies looking towards the future valueof selling their newly won capability.
Milestone payments must remain focused,however, on rewarding performance. They should
not be transformed into a type of up-front cost
sharing. Companies must make the up-front
investments, and upon reaching a milestone andvalidating that achievement with a commitment
to move on to the next stage, they should receivea pre-specified payment from the government for
their performance. The amount of the milestone
payment should be determined in advance andshould not be adjusted to cover cost overruns.
Breaking the development process into milestones
also creates options for responding to interim
results and modifying or adapting the process ifnecessary. It allows companies to obtain cyclesof funding based on interim demonstrations ofsuccess, including payouts received midway.
And, it makes it possible to stop a failing project
before further expenses are incurred. Negotiatinginterim milestones up front also helps define allparties’ mutual responsibilities, including thegovernment’s necessary role regarding fuel andwaste. Under NASA’s COTS program, one of thefirst two recipients of a completed agreement
was scheduled to receive a total of $207 million
for completing all milestones. Early on, however,the company failed to demonstrate that it had
obtained the next round of financial backing
needed to proceed. As a result, the agreement
was terminated after only $32 million in NASAfunding had been paid out. NASA put out a new
solicitation and the new company that came inultimately completed all the milestones (National
Aeronautics and Space Administration 2014).
Production credits work like production tax credits.
They are set at a pre-specified unit amount($/MWh) and awarded for the quantity ofelectricity generated over a window of time.
Typically, an upper limit is set on the quantity of
production that can receive the credit. Payment
is made when production occurs—for example,

as electricity is sold onto the grid. The reactor
owner receives both the market price for theelectricity and the supplementary production
credit.
Production credits have important advantages asa lever for providing support. First, because they
reward performance, they leave private businessbearing the important technology and construction
risk. If a reactor is never completed, then the
supplementary production credit is never paid. If
a reactor is completed with delays or at greater
cost than originally estimated, the size of the
supplementary production credit is not adjusted
and the reactor builder earns a smaller profit orsuffers a loss. This creates a strong incentive forprivate investors to guide the innovation process inthe most cost-efficient direction.
Second, production credits are readily grafted
onto a larger system without coming into conflictwith important rules and principles of that system.
In particular, they are preferable to mandating
special purpose power purchase agreements(PPAs) in which government agencies ordepartments commit to purchase power fromparticular reactors. Normal PPAs are negotiatedwith the objective of providing the government
with a commodity service at commercial prices.
There are rules and principles that govern how
normal PPAs are negotiated and how their terms
are evaluated. Special PPAs intermingle a subsidy
with a commercial transaction and make it
difficult to enforce the normal rules and principles
associated with procuring power. Instead ofresorting to a special PPA, production credits
separate the problem of providing a subsidy fromthe commercial transaction. Contracting for a
PPA proceeds as always, without interference
and subject to all the rules and principles that
normally govern the procurement process.
The production credits are then a simple add-on
to whatever normal commercial arrangements
are made for the sale of power. In other words,
the credits are completely separable. Whateveramount of financial support could have been
provided through a special PPA can also be
provided by adding a supplemental production
payment on to a normal PPA.

Chapter 4: Nuclear Industry Business Models and Policies

111

The size of the supplementary production credit
is flexible. To be efficient, it should reflect thesocial value of accelerating innovation in advanced
nuclear energy technologies.
Recommendation:

Governments should establish programs
to fund prototype testing and commercial
deployment of new, advanced reactor
designs. These programs should focus
on four levers for advancing progress
toward commercialization:
1.

Funding to share R&D costs related tomoving new reactor designs toward theconstruction of a demonstration reactor,

2. Funding to share licensing costs

for new demonstration reactors
and commercial designs,

3. Funding for milestone payments

for construction and operationof a demonstration reactor, and4. Funding for production credits to reward

successful demonstration of new designs.

We use the two hypothetical examples
constructed earlier to show how a proposed
government funding program would align with theGovernment
Funding Program

Table 4.3: Input values for illustrative examples ofsources of government support for two alternativeadvanced reactor development projects

6112HigherMaturity
Technology

Lower
Maturity
Technology

Rate for R&D cost sharing

50%

50%

Rate for licensing cost
sharing50%

50%Rate for milestones

21%

31%

27

27

Production credit, $/MWh

investments needed to demonstrate a new reactor
and how this support would affect the time horizon
for earning a return on investment.
Table 4.3 shows specific assumptions for the four
funding levers discussed previously. Using these
input values, Table 4.4 itemizes costs, government
funding, and net investor cost for the high maturity
technology. Column A shows specific phases of
the technology development process. The different
levers of government funding appear in columns
C through F, while column G shows the total
amount of government funding.6 Disbursements
under the R&D cost sharing and licensing columns
occur simultaneously as costs are incurred.
Disbursements for milestone payments occur
with a lag: the company first spends money toaccomplish the milestone and then receives
payment. An actual agreement would containmany intermediate milestones, so the payments
shown here reflect an aggregate. A subtotal isshown for expenditures and payments throughcompletion of the development phase and before
production credits are earned on generation.
At the end of the development phase, government
funding has covered 23% of expenses, and theinvestors’ net cost is 77%. The amounts shown
under column F represent the present value of
production credit payments to be made overtime for generation produced. The column shows
production credits for output from the commercial
demonstration reactor on the assumption thatthe reactor continues operating after testingis completed and a design license has been
approved. The column also shows payments
earned on future builds. The amounts shown
correspond to a $27/MWh payment earned ona total capacity of 1.25 GW operating at a 90%
capacity factor for 10 years using a 10% discountrate. These production credits are equal in value
to 26% of the development cost. Therefore, inthis illustrative example, government funding inaggregate covers 50% of the total development
cost, with 23% coming from the combination

 ot explicitly shown in the table is the government expense to establish the reactor park and provide fuel andNspent fuel management services. The government will incur up-front costs to establish a reactor park and outfit itwith infrastructure and to establish generic fuel and spent fuel capabilities. Companies can be charged for certain
services, which will defray some of the government’s costs. Companies will contract for some specific fuel andspent fuel handling services. Both of these type of costs are contained in the table.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Table 4.4: Illustrative example of government funding levers for the high maturity technology example
Government Funding

Early
Development

Commercial
Demonstration

Total
Federal[G]

Net
Investor Cost
[H]

R&D
[C]

R&D

50

25

25

25

Design & Engineering

100

21

21

79

Supply Chain

100

21

21

79

Design & Engineering

100
200

Construction

1,725

Operation & Testing200

Subtotal at end development
Commercial
Operation

Production
Credits
[F]

Cost
[B]

Licensing

Licensing[D]

Milestone
Payments
[E]

Item
[A]

21

21

79

100

100

365

365

1,360

42

42

158

596

1,879

100

2,475

25

100

471

1%

4%

19%

Demonstration plant

456

Next 4 modules

76%

456

-456

186

186

-186

25

100

471

642

1,238

1,238

1%

4%

19%

26%

50%

50%

2,475

Total

24%

(all figures in $ millions)
Table 4.5: Illustrative example of government funding levers for the low maturity technology example
Government Funding

Early
Development

Performance
Demonstration

Total
Federal[G]

Net
Investor Cost
[H]

150

150

62

138

R&D
[C]

R&D

300

150

Design & Engineering

200

62

Supply Chain

200

62

62

138

Design & Engineering

300

93

93

207

100

100

Construction

2,300

716

716

1,584

Operation & Testing

400

125

125

275
2,592

Subtotal at end development
Commercial
Operation

Production
Credits
[F]

Cost
[B]

Licensing200

Licensing[D]

Milestone
Payments
[E]

Item
[A]

3,900

100

150

100

1,058

1,308

4%

3%

27%

34%

66%

Demonstration plant

456

456

-456

Next 4 modules

186

186

-186

Total

3,900

150

100

1,058

642

1,950

1,950

4%

3%

27%

16%

50%

50%

(all figures in $ millions)of government funding for R&D, licensing, andmilestone payments, and another 26% comingfrom production credits earned on generation.

the investors recoup their investment in year 19.
The figure also illustrates the way that production
credits are paid out later, as production occurs.

The role of government funding is shownin Figure 4.3 where the second, purple line
represents the total present value of investors’
net cost. Because of government payments,

Table 4.5 shows comparable results for the low
maturity technology. The impact of government
funding appears in Figure 4.4 in the smaller total
for cumulative net investor cost. As in Figure 4.3,
the second, purple line shows the total present

Chapter 4: Nuclear Industry Business Models and Policies

113

value of investors’ net cost. Because of thegovernment payments, the investors’ recoup theirinvestment in year 39. As with the high maturity
technology, production credits are paid out later,as production occurs.
The estimates shown here and in various
government reports all assume that thetechnology development program proceeds
through this sequence of steps to a final,
successful conclusion. Provisions are madeearly on for a review of multiple options, butthese examples assume a down selection to thewinning option, which is the one option for whicha prototype is constructed. Success is presumed
through every milestone. Under the program wehave detailed, the same steps and costs would
be incurred to arrive at the endpoint of one ormore new reactors that have been prototyped
and licensed, and are ready for deployment.
A key feature of our proposed program, however,is that by leaving the choice of which technology
to pursue to private investors, we also ask
these investors—rather than the government—
to assume associated risks, meaning that they
bear both the potential for profit and the riskof loss. The government does not, in the first
instance, assume direct responsibility for all costs.
Companies are expected to cover the costs ofengineering design work and, most importantly, ofreactor construction. This funding program allows
the government to provide milestone payments
as a prototype reactor is successfully constructed,
tested, and operated to provide data in support oflicensing. These payments can be viewed as a kindof reward intended to reimburse companies for thecost of design and construction. However, thesepayments are not guaranteed. They are contingent
on the achievement of defined milestones.7
Moreover, the size of the milestone payments isfixed up front, and the company bears the full riskof achieving each milestone in a cost-efficient way.

7

114

A second key feature of this proposed approachis that it recognizes the contingency inherent
in any effort to support innovation. There isno single direct, unbroken path through R&D,
onward through design, and through prototype
to deployment. A venture cannot simply barrel
forward down a path that has been laid out fromstart to finish. The process begins with uncertainty
and must incorporate new information along theway. One of the striking features of the current
moment of innovation in Gen-IV reactor designs
is the array of different startup companies thathave been founded to produce different designs
and that have received early-stage funding. These
startups exist alongside several major companies
that have long been part of the industry and thatare advocating different Gen-IV designs of theirown. There is no reason to ask the government topick one winner. Instead, the government should
enable a healthy competition. If multiple designs
can succeed in finding investors willing to provide
the capital required to finance their up-front
engineering costs, then multiple designs should be
tried. Along the way, each design will encounter
successes and setbacks. Some designs mayneed to be abandoned. Others may need to be
reworked, in which case the realized up-front costs
will be higher than had been hoped. And somedesigns may proceed forward as planned. The final
amount that is spent on any particular design will
be highly contingent on the number of companies
that make the assessment that it is worthwhile toinitiate a project. It will also be highly contingent
on what those companies learn along the way andhow many decide to continue.
The government’s role, however, should be morestable. One role is to provide an enabling platform
where prototyping can be done. The government’s
up-front investment to provide this platform will
be relatively fixed, insofar as the cost of building
needed infrastructure and support facilities isrelatively fixed. The government’s facilities fortesting and prototyping new reactors shouldbe open to a wide variety of designs, but an
optimist might expect perhaps two or three ecall that in the first round of NASA’s COTS program, two agreements were made with SpaceX and Rocketplane
R
Kistler. However, Rocketplane Kistler failed to raise the necessary private capital and NASA terminated theiragreement. This freed up $175 million to go to other companies.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDto become operative in the short-term—thus,
it is unlikely that capacity constraints will need
to be adapted very quickly. If one of the first
designs proves a success, that may open up
capacity for new designs to use the prototyping
facility. Another role for government is to provide
funding to support and encourage prototypes.
This support should be relatively fixed and limited.
And if success is achieved in shepherding one
or two projects to licensing, subsequent projects
should need less support.

Chapter 4: Nuclear Industry Business Models and Policies

115

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Bryant, Susan Montoya. 2017. “New Mexico, Texas Seek
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Canadian Nuclear Laboratories. 2017a. “2016–2026
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Chapter 5

Nuclear Reactor Safety Regulationand Licensing
This chapter begins with a discussion of the regulatory framework used to license nuclear
reactors. We then provide a brief history of nuclear regulation in the United States todemonstrate the evolution of nuclear safety regulation and licensing principles. Next, wecharacterize regulatory and licensing frameworks in other countries. Finally, we focus
on the U.S. regulatory system and review best practices and areas of improvement forlicensing and regulating advanced reactors.

5.1 NUCLEAR REACTOR SAFETY
The safety of a nuclear reactor system depends
on a set of safety functions that must be
satisfactorily accomplished to control the reactor
under normal operation and to assure its safety
if an off-normal event, either internal to theplant or due to an external hazard, were to occur.
Such safety functions would remove residual
heat from the reactor core to assure long-termcooling of the core when the reactor is shut down.
Successful completion of these safety functions
prevents or limits to acceptable levels the releaseof radioactive materials into the environment.
The safety functions that must be maintained for
all reactor systems include:• Control of reactor reactivity during startup,
operation, and shutdown;• Control of heat removal to an ultimate
heat sink;• Control of coolant inventory (volume,
temperature, flow rate); and• Control of any chemically reactive
or radiological materials.
Nuclear reactors must be designed with safety
features and systems that can successfullycomplete these safety functions. This includes
design, operation and maintenance of supporting

systems (electric power, cooling, pressurized
air, etc.) that are required to accomplish thesafety functions. Reactor designs must also
provide, where appropriate, physical separation,
independence, diversity, and redundancy in safetysystems to reduce the likelihood of common‑cause
or single‑point failures that could lead to failurein executing a safety function. Finally, designs
must utilize defense-in-depth and engineering
margins to cover the possibility that challenges tosafety functions could arise from an incomplete
understanding of reactor system behavior. Thesedesign principles are intended to ensure all safetyfunctions are successfully completed and that theoverall reactor system is safe.
The role of nuclear reactor safety regulationand licensing is for the government to review
and independently verify that a given nuclear
reactor system design can perform needed safetyfunctions with reasonable assurance to protect
public health and safety, and the environment.
Worldwide, 85% of all currently operating
commercial nuclear reactors are light water
reactors (LWRs) that use slightly enricheduranium fuel and are cooled by water(International Atomic Energy Agency 2017).
In current LWRs, critical safety functions areaccomplished through a combination of active
and passive backup systems (e.g., reactor

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

117

shutdown, cooling, and electrical systems) andoperator actions. These systems reduce thelikelihood of safety function failure and mitigate
the consequences should a failure occur. Specificdesign criteria assure that system conditions
that could drive possible radiological releases arecontrolled for a range of postulated design basis
accidents (U.S. Nuclear Regulatory Commission(NRC) 2007c). For advanced reactor systems,
these safety functions are integrated in the systemdesign with a greater emphasis on inherent
and passive design features1 than in current
LWRs (NRC 2008). Chapter 3 reviews technicalinformation and safety characteristics for specificadvanced reactor designs.
The current safety regulation and licensing
framework for commercial nuclear power plants
is the product of policy evolution that has been
driven by social and political forces, increasing
knowledge of nuclear power design and operation,and major industry events with associated lessons
learned. While different countries have different
regulatory processes based on their historicalexperiences and economic and political systems,
the basic principles of nuclear regulation are quite
similar around the world.

5.2 CHARACTERIZING REGULATORYFRAMEWORKS
The regulatory frameworks used to review thesafety of nuclear power plants and license newplants can generally be described in terms of
three characteristics:• Technology—Can the framework be used toregulate any generic nuclear reactor technology
or are its requirements technology-specific?
• Risk—How does the framework consider
licensing event risks (probability andconsequence) in determining requirements?

1

118• Prescriptive or Performance-Based Requirements—
Is plant safety determined by implementingprescribed design and operational features orby evaluating overall plant performance?
Though different regulatory frameworks may
have the same end goal—i.e., adequate protectionof public health and safety—the choice of aparticular framework will have an impact on howtechnologies are regulated and how the industry
thinks about and addresses safety.

Technology
A regulatory framework can be written to workwith specific reactor technologies (technologyspecific) or to allow more broadly for regulation of
any reactor technology (technology-neutral).
Technology-specific regulatory requirements havebeen refined for a particular reactor technology.
This reduces uncertainty for applicants because
it provides specific performance requirementsthat applications will be evaluated against andhelps ensure consistent application of regulation(Walker and Mazuzan 1992). Additionally,
technology-specific requirements can reduce
repeated licensing efforts and help ensure consistent
implementation and enforcement of regulations.
One significant drawback of technology-specificrequirements is that they may discourage
innovation and delay the review of novel reactor
concepts, such as the high temperature gas-cooled
reactor (HTGR), or concepts that are a significant
variation on existing technologies, such as theintegral pressurized water reactor (iPWR) (Petti,
et al. 2017). New technologies that do not havea regulatory precedent can encounter significant
licensing challenges in a technology-specificregulatory framework. Conversely, the primaryadvantage of a technology-neutral regulatory
framework is that novel reactor concepts may be
more easily accommodated (Finan 2016).

 he International Energy Agency (IAEA) defines active, passive, and inherent safety features as follows
T(IAEA 1991): Active safety features “rely on external electrical or mechanical power, signals, or forces to completea safety function.” Passive safety features “only require natural forces (gravity or gas pressure), properties ofmaterials, or internally stored energy to complete a safety function.” Inherent safety features “rely on fundamental
properties (materials or design choices that cannot be changed by internal or external conditions) to complete asafety function. An inherent safety feature has no failure mechanism.”

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDIn a technology-neutral framework, requirements
are written in a manner that allows for application
to any reactor technology. However, theserequirements often lack the specificity necessary
to ensure consistent and uniform interpretations
by regulatory staff and applicants (NRC 2007b).
While this adaptability can be valuable for new
technologies, it may slow the licensing process.
A technology-neutral licensing framework canprovide guidance for developing and applying
needed technology-specific criteria (NRC 2007d).
A mixed framework could support licensingof any reactor technology but also capture
lessons learned and allow expedited licensing
for applicants that reference and incorporate
established regulatory precedents (NRC 2007b).

Risk
A regulatory framework can also be characterizedbased on how it considers the risk of specificpossible accident sequences. Overall risk isdefined, for purposes of this discussion, by the‘risk triplet’: (1) what can go wrong (definitionof the event sequence), (2) how likely is it to go
wrong (the sequence probability), and (3) what
are the consequences of the sequence. Threeapproaches have commonly been used toevaluate safety risks for nuclear power plants
as characterized by the ‘risk triplet’ (ViettiCook 1999):• Deterministic—Regulatory requirements are
based on event sequence definition and event
sequence consequences. Event sequence
probability is not explicitly considered whensetting deterministic requirements.
• Risk-Based—Regulatory requirements are
based on the event sequence probability andconsequences using best estimate values.
Conservative assumptions of failures orconditions are not considered, but uncertainties
are considered.
• Risk-Informed—Regulatory requirements are
based on deterministic requirements derived
from dominant event sequence probabilities.
Event sequences chosen for safety analyses are
based on risk but limiting safety analyses that
include uncertainty analyses or conservative
event sequence definitions can be performed.

These different approaches to risk assessment
have varying benefits and drawbacks and areclosely linked to the historical development of
nuclear regulation in the United States. While adeterministic regulatory approach may focus on
extremely high consequence events with nearzero probability, a risk-informed or risk-based
regulatory approach may instead focus on an
initiating event with lower consequence but higher
probability because the total risk from such events
is higher (Vietti-Cook 1999) (see Sidebar 5.1).
A risk-informed framework is useful because theinsights gained from probabilistic risk assessment(PRA) can guide design decisions, safety analyses,
and help develop specific safety criteria. This
type of framework acknowledges the potential
safety and design benefits from incorporatingrisk information while also accounting for theuncertainties inherent in current ‘state of the art’
PRA and the use of deterministic principles suchas defense-in-depth where required by social
safety goals (NRC 2007b). For advanced reactor
designs with limited operating experience, theuse of PRA allows for a greater understanding of
the relative risk of different event sequences andthe design features of critical safety functions.
PRA was used extensively and successfully in
regulatory reviews of conceptual designs forthe proposed modular HTGR as part of a draft
preliminary safety evaluation (Williams, King, andWilson 1989).

Prescriptive or Performance‑Based
Requirements
Technical requirements can be either prescriptive
or performance-based. Prescriptive requirements
specify the design features, analysis techniques,or operational practices that an applicant must
use to satisfy a safety objective. An example
would be requiring specific maintenance, testing,and inspection of emergency diesel generators
at specified time intervals to ensure reliability(Kadamabi 2002). By contrast, performancebased requirements present an overall safety
objective or metric that must be met by thedesign but allow the applicant to select the
specific design features, analysis techniques, or
operational practices that can satisfy the objective.

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

119Sidebar 5.1: Consequences, Probability, and Risk
in Historic Approaches to Nuclear Safety Regulation
A major feature of deterministic regulatory approaches is the useof bounding analyses that consider system performance against
a single limiting or worst-case event. For example, to develop
deterministic safety requirements to address the risk of coolant
loss—also known as ‘loss of coolant accidents’ (LOCA)—U.S.
regulators have defined the bounding or worst-case event as“a break equivalent in size to the double-ended rupture of thelargest pipe of the reactor coolant system” (NRC 2007c). The
rationale is that a system designed to survive the most severe
accident of this type, in other words, a ‘large-break LOCA,’
would also be able to survive all smaller break events (smallbreak LOCAs).
This deterministic approach has two problems: The first is thelow probability that the bounding event will actually occur.
The second arises from a conflation of consequence and risk interms of decision-making. Engineering analyses of pipe systems
suggest that the likelihood of a pipe failing in a double-ended
rupture is extremely small given the ductility of the pipe (whichmakes it far more likely that a pipe would leak before it breaks)
and the extremely high loads required to generate stresses
sufficient for a double-ended rupture (Holman 1984). Whilethe consequence of a large-break LOCA could be exceedingly
high, the likelihood of this event is also exceedingly low.
Use of large-break LOCA as a bounding event in regulatory
determinations for nuclear power plants has resulted insafety features and systems that are specifically designed
for that event. One weakness of this approach is that smaller
consequence events may not always be completely bounded. For
example, the Three Mile Island (TMI) accident demonstrated thatthe safety features used to mitigate a large-break LOCA could
not mitigate a small-break LOCA under all plant conditions. This
resulted in a series of system failures at TMI and an inadvertent
release of radiological materials. While the consequencesof an unmitigated small-break LOCA might be less severe
in some scenarios than those of an unmitigated large-break
LOCA, the higher probability of occurrence for a small-break
LOCA can mean that this type of event creates a higher total
risk. Sole reliance on deterministic analyses that design for theconsequences of a single bounding event without considering
the probability (and, by extension, the risk) associated with thatevent may cause designers to miss or underestimate the impactsof lower-consequence, higher-probability events.
For new reactor designs with limited or no operating experience,
a combination of deterministic methods and risk analysis
methods would provide a risk-informed approach to safety
regulation that balances consequences, probability, risk, anduncertainty to deliver better public health and safety protection.

120

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Requiring diesel generators or other backup powersources to show 95% reliability of operation for
design basis accidents would be a performancebased requirement (Kadamabi 2002).
In sum, prescriptive requirements specify how
safety objectives must be accomplished while
performance-based requirements specify whichsafety objectives must be accomplished. The
major advantage of prescriptive requirements
is that they reduce regulatory uncertainty andprovide applicants with clear criteria for licensing;much less engineering judgment is required
during evaluations by regulatory staff. The major
disadvantage of prescriptive requirements is thatthey focus on the method used to achieve thesafety objective and not on the final objective
itself. This disadvantage has two implications.
First, it discourages innovative safety solutions
because the need to seek exemptions createsa barrier to implementation (Finan 2016).
Second, focusing on the method and not theoutcome can result in less emphasis on ensuringthat the ultimate safety objective is fulfilled byprescribed methods.
Performance-based requirements specify whichsafety objectives must be met and emphasize thatapplicants must demonstrate how their design
fulfills safety objectives. The major advantageof this approach is that it can allow for designand operational flexibility and can be adapted to
any reactor technology if the safety objectives
specified are sufficiently broad (e.g., off-sitedose limits for accident conditions). The major
disadvantage of performance-based requirements
is that engineering judgment has to be used toevaluate uncertainties and assess whether therequirements have been met—and such judgments
are open to interpretation by applicants, staff, andother reviewing bodies, such as the U.S. Nuclear
Regulatory Commission’s Advisory Committee
on Reactor Safeguards (ACRS) and Atomic Safety
Licensing Board (ASLB), as well as interveners andcourts (Coglianese, Nash, and Olmstead 2003).
Flexibility can result in regulatory uncertainty
and may delay projects if significant analysis,
experiments, or redesign are required for an
applicant to demonstrate that the reactor design
satisfactorily fulfills the safety objectives.

A performance-based framework that introduces
technology-specific requirements only where suchrequirements are actually needed gives applicants
maximum flexibility to innovate on reactor
designs and features while ensuring adequate
protection of public health and safety. Limited useof technology-specific requirements helps improve
regulatory transparency and increases public
assurance that lessons learned from the operationof existing plants will be captured and included infuture designs to increase overall plant safety.

5.3 DEVELOPMENT OF NUCLEARREGULATION IN THE UNITED STATES
Nuclear regulation in the United States has
evolved since the creation of the Atomic Energy
Commission (AEC) in 1946 and the passage of
the Atomic Energy Act of 1954 that launched thedevelopment of the commercial nuclear powerindustry. This evolution has been shaped by thechanging state of knowledge regarding nuclear
power plant design and operation, as well as bychanging public opinions about nuclear power.
The regulatory authority for the first commercial
nuclear power reactors and prototypes in the
United States was the AEC, which was tasked
with developing, promoting, and regulating thefledgling nuclear power industry (Hogerton1963) (Mazuzan and Walker 1985). In the 1950s
and early 1960s, the federal government’s
support of nuclear energy led to the design andconstruction of a wide range of different reactor
technologies, both as demonstration systems
and for commercial use (Hogerton 1963). Thesepublic/private commercial reactors included(International Atomic Energy Agency 2017):• Light water reactors (Shippingport
Reactor 1957),• Sodium-cooled fast breeder reactors (Enrico
Fermi Reactor Unit 1 1963),• Sodium-cooled and graphite moderated
reactors (Hallam Nuclear Facility 1963),• Organic-cooled and moderated reactors(Piqua Nuclear Reactor 1963),• Heavy water reactors (Carolina Virginia Tube
Reactor 1963), and• High-temperature gas reactors (Peach Bottom
Reactor Unit 1 1966).
Given that reactor technologies were stilldeveloping, the AEC had to regulate individual
reactors on a case-by-case basis, relying on
limited experimental data, engineering judgment,
and expert advice from the ACRS to establish
the technical basis for licensing and operation(Mazuzan and Walker 1985).
Reactor safety was satisfied largely through four
strategies (Mazuzan and Walker 1985):• Remote Siting—putting reactors in sparsely
populated areas to limit public exposure in caseof accidental release.
• Containment—including structuresand systems to limit accidental
radiological releases.
• Low Reactor Power—using designs that
resulted in a smaller source term ofradionuclides from accidents.
• Engineering Margin—adding engineering
design margins to account for uncertainties.
While case-by-case evaluations enabled theconstruction and licensing of novel reactor
designs, the AEC’s congressional oversightcommittee, the Joint Committee on Atomic
Energy, and the industry sought formalized design
criteria for nuclear power plants. Development ofthese criteria was intended to reduce regulatory
uncertainty and shorten licensing review
periods by aligning the applicant’s preparedsafety analysis with AEC staff expectations(Walker and Mazuzan 1992).
AEC technical staff first developed general design
criteria in 1971. These criteria outlined the generaldesign characteristics required for commercial
plants and the types of technical information thatapplicants were expected to include in a nuclear
power plant license application. As AEC staff
revised draft design criteria based on industry
groups and the public feedback, the criteria

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

121

shifted from general, technology-neutral criteria to
specific requirements for LWR technology, which
industry had selected for first commercialization.
The formalization of technology-specificreactor requirements was designed to optimize
plant designs and introduce more regulatory
certainty for LWR technology. In 1974, theEnergy Reorganization Act separated the AEC’s
nuclear development and regulatory functions.
The nuclear development function was assigned
to the new Energy Research and Development
Administration (later merged with the Federal
Energy Administration to form the Department ofEnergy), and the nuclear regulatory function was
assigned to the new U.S. NRC.

industry events (which illustrated strengths andweaknesses of existing plant designs) and publicconcerns related to the safety of nuclear power
plants. While reactors of varying ‘advanced’
designs were safely constructed and operated
in the early 1960s, regulatory optimization toincrease regulatory certainty led to LWR-focusedlicensing guidelines and processes. Changes inthe basic safety philosophy applied to nuclear
reactors, increasing reactor sizes, and siting
policies changed the number, type, and stringencyof regulatory requirements for nuclear power
plants. Table 5.1 summarizes current principles ofnuclear safety along with an industry event that
demonstrated the importance of these principles.

Current principles of nuclear regulation andsafety have evolved based on increased technicalunderstanding and lessons learned from major

While this discussion has focused on U.S.
regulatory history, the evolution of safety
regulations and the lessons learned that have

Table 5.1 Regulatory Safety Principles
Safety Principlea122

Definition

Case Examplea

Reactor Siting

The location of a nuclear power plant can significantly impact the risks posed by thatplant. Siting reactors away from population or agricultural centers can help minimize
public exposure and consequences in the event of an accident.

1961 SL-1 Nuclear
Reactor Accident

Defense in Depth

Use of multiple independent and redundant barriers to prevent and mitigate
accidents so that no single layer, no matter how robust, is exclusively relied upon toprevent the release of radiological materials.

1966 Fermi Unit 1
Fuel Melt Incident

Redundant andIndependent
SafetyUse of multiple, physically separated, independent, and fully redundant components
or systems when the performance of the safety function is necessary to prevent andmitigate accidents.

1975 Brown Ferry
Unit 1 Cable Fire

Human Factors

The probability of success or failure of operator actions must be considered when
designing safety systems. Operators will not always make timely or correct decisions
when called upon and the potential for these errors must be accounted for in thedesign of systems and components.

1979 Three Mile
Island Unit 1
Accident

Inherent Reactor
SafetyControl and operation of nuclear power plants should be inherently stable based on
the physics of reactor design. This inherent stability can be defined by the feedback
mechanisms or long-term behavior of different reactor characteristics such as
thermo hydraulic or neutronic performance.

1986 Chernobyl
Nuclear Accident

Active vs. Passive
SafetyActive safety systems require external action (e.g., operator action, electric motors
and valves) to fulfill their safety function. Passive safety systems fulfill their safetyfunctions without external action and only rely on natural forces (e.g., gravity,pressure differential). The safety implications of passive and active systems differ
based on application and design.

2011 Fukushima
Nuclear Accident

Conservative
Calculations
to Account for
Uncertainties

The design of nuclear systems requires the use of parameters and values that are
subject to high amounts of uncertainty. Calculations related to the safety of nuclear
facilities must appropriately consider these uncertainties or use bounding ‘worst
case’ values to create a safe operating envelope for the plant.

2011 North Anna
Power Station
Seismic Event
Exceeds Plant
Design BasisEach case example results from a confluence of multiple safety principles but is provided to illustrate the impact of a particular failure oran individual safety principle.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDinfluenced this evolution are similar in mostcountries. Thus, although other countries havedeveloped slightly different approaches toassuring plant safety, the fundamental principles
remain the same (International Nuclear Safety
Advisory Group 1999). Differences in regulatory
frameworks are largely attributable to differencesin cultural expectations of safety, political systems,
and economic systems.

5.4 NUCLEAR REGULATION AROUND
THE WORLD
Nuclear regulation in most countries has evolved
over a period of decades to support the mostefficient licensing of a single reactor technology.
In most cases, this has resulted in regulatory
systems optimized for the regulation of large,
light-water-cooled nuclear reactors. In Canada andthe United Kingdom, the major indigenous reactor
technologies are not light-water-based, but rather
heavy-water-cooled and carbon-dioxide-cooled,respectively, and each country’s regulations
were optimized for the design and operationof their single dominant reactor technology.
Different regulatory agencies have also evolved
as the priorities of the national government andpublic/legislative discussion have shifted overtime. The impact of the major nuclear accidents(Three Mile Island, Chernobyl, and Fukushima)on regulations worldwide was significant.
These international incidents highlight the pointthat nuclear safety is not solely a national issue:
the consequences of a nuclear accident, both
physically and psychologically, are experienced
worldwide. The 1994 Convention on Nuclear
Safety (CNS), organized by the International
Atomic Energy Agency (IAEA), worked toaddress these issues by establishing a common
international basis for nuclear safety (IAEA 1994).
The Convention had several objectives:
1.

To achieve and maintain a high level of nuclear
safety worldwide through the enhancementof national measures and international
cooperation including, where appropriate,safety-related technical cooperation.

2.

To establish and maintain effective defenses
in nuclear installations against potential
radiological hazards to protect individuals,
society, and the environment fromharmful effects of ionizing radiation fromsuch installations.

3.

To prevent accidents with radiologicalconsequences and to mitigate suchconsequences should an accident occur.

These high-level objectives, together with efforts
to implement the IAEA’s basic safety principles fornuclear power plants (International Nuclear Safety
Advisory Group 1999), allowed development ofdifferent national regulatory structures while still
promoting international accountability for nuclear
regulation and safety.
Though their ultimate safety objectives are thesame, cultural and political differences have
led to variations in how countries implement
nuclear regulation. These variations include
both philosophical and practical differences.
Philosophical differences with respect totechnology-specific vs. technology-neutral
requirements, deterministic vs. risk-based
evaluations, and prescriptive vs. performancebased requirements result largely from differing
cultural approaches to nuclear safety. Practicaldifferences on issues such as the renewal
frequency for reactor licenses—for example, 5years in Canada, 10 years in France, 20 years in
the United States—result from differing politicalenvironments. These philosophical and practicaldifferences will have a notable impact on thelicensing of new reactors in the next several
decades and may enable new nuclear technologies
in some countries while precluding them in others.
While national autonomy has been a cornerstoneof nuclear reactor licensing, acceptance ofinternational best principles and better alignmentand cooperation between national regulators
could remove unnecessary hurdles to enabling
the worldwide deployment of new nuclear power
plants. The design, construction, and deploymentof nuclear reactors has always been an activity
that occurred in many different countries. It is a

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

123

global enterprise, but one that has been characterized
by different design concepts. Enabling vendors tosell a single standardized design worldwide would
reduce costs, shorten development schedules,
and lessen licensing burdens. A standardized
international deployment paradigm, however,requires alignment and agreement between
different nuclear regulators to reduce or eliminate
duplicative review efforts and allow for a uniform
set of safety standards that are more specific thanthose currently agreed to in the CNS.

Nuclear Regulation in the United Kingdom
In the United Kingdom, commercial nuclear power
plants are licensed and regulated by the Officeof Nuclear Regulation (ONR). The ONR is a fully
independent governmental agency that oversees
nuclear safety as well as the use and transportof civilian nuclear materials (U.K. Department of
Business, Energy, and Industrial Strategy 2017).
The ONR was created in 2014 and integrates
separate government offices that had previously
overseen nuclear installations, nuclear security,and nuclear safeguards. It was created to enable
the effective licensing of new nuclear power plants
and oversee an expanding nuclear industry.
Regulation of nuclear facilities in the United
Kingdom is almost entirely performance-based;
the ONR sets high‑level regulatory expectations
and allows applicants wide flexibility indetermining how to meet and demonstratecompliance with these standards. The ONR
believes that a performance-based regulatory
paradigm allows for innovation in safety,
enables novel technologies, and “strengthensaccountability and encourages the adoptionof relevant good practice and continuous
improvement” by nuclear facility licensees.
U.K. nuclear facility regulation is site-based.
The ONR first approves a specific site for theapplicant’s proposed activities and then grants
the applicant specific permissions (license
instruments) to proceed through different
stages of facility construction, commissioning,and operation. The initial site review process
determines whether the applicant’s safety case for124

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

the overall facility and site would protect public
safety; its purpose is not to review a particular
reactor design.
Regulatory documentation of a specific reactor
design and safety analysis is submitted on
an agreed-upon schedule throughout facility
construction and commissioning. A generic design
assessment (GDA) process was created to help
expedite reviews of standardized reactor designs
and allow for earlier regulatory intervention andfeedback in the design and licensing process. The
GDA is non-binding but “will make a significant
contribution to ONR’s assessment of the license
applicant’s safety case.”

Nuclear Regulation in Canada
In Canada, commercial nuclear power plants arelicensed and regulated by the Canadian Nuclear
Safety Commission (CNSC). The CNSC is a fully
independent governmental agency that oversees
nuclear safety as well as the use and transportof civilian nuclear materials (Canadian Nuclear
Safety Commission 2016). It was created in 2000,
replacing the Atomic Energy Control Board that
had acted as Canada’s regulator for all nuclear
energy activities since 1946. This change wasintended to ensure independence of the nuclear
safety regulator from development activities,
and to allow the CNSC greater legal power in thereview, approval, and enforcement of licenses.
Regulation of nuclear facilities in Canada istypically non-prescriptive; current regulatory
guidance is largely technology-neutral and the
CNSC is working towards making regulations
performance-based and risk-informed whereappropriate. The CNSC aims to set “general,
objective, performance-based regulatory
requirements” and allow applicants to develop
their own methods for meeting the requirements.
However, more specific requirements may beestablished where necessary. The CNSC has also
put greater emphasis on risk-informed regulations;risk-graded approaches to safety analysis can beused both by applicants when preparing facility
designs and by CNSC staff when determining
focus areas and scope of assessment for
regulatory review.

In Canada, nuclear power plant regulation isphase-based. The life cycle of a nuclear facility is
divided into five distinct phases: site preparation,
construction, operation, decommission, andabandonment. Each phase requires a separate
regulatory review and approval. While each ofthese reviews is separate and distinct, applications
for the first three phases (site preparation,
construction, and operation) can be assessedby the CNSC in parallel provided that sufficient
information is submitted by the applicant.
Regulatory review and safety analyses for a
specific reactor design (the safety case) areconducted throughout the first three phases of
the regulatory process, with increasing levelsof design detail and technical review. The
pre-licensing vendor design review (VDR) was
created to “verify, at a high level, the acceptabilityof a nuclear power plant design with respect to
Canadian nuclear regulatory requirements andexpectations, as well as Canadian codes andstandards” (Canadian Nuclear Safety Commission2012). The VDR is intended to help vendors
identify fundamental barriers to licensing andpaths to resolve any serious design issues
identified by the CNSC. The process is fully
optional for applicants and VDR conclusions arenon‑binding and non-influencing for the CNSC in
subsequent licensing reviews for plant designs.

Nuclear Regulation in China
In China, commercial nuclear power plants
are licensed and regulated by the National
Nuclear Safety Administration (NNSA) within
the Ministry of Environment Protection. The
NNSA is an independent governmental bodythat oversees nuclear safety as well as the useof all civilian nuclear materials and activities(The People’s Republic of China 2016). It iscomplemented by the China Atomic Energy
Authority, which promotes and implements thepeaceful use of atomic energy in China, and by the
National Energy Administration which provides
technical standards and advice on nuclear power
plant projects.

Regulation of nuclear facilities in China is based
primarily on deterministic methods, althoughprobabilistic and risk-informed methods havebeen required to support and validate theconclusions of deterministic safety analyses
since 2009. Probabilistic methods are also being
implemented for operational considerations suchas risk-informed maintenance activities. Despite
requirements that appear to be largely prescriptive(e.g., specific acceptance criteria, conservative
assumptions), the NNSA has successfully licensed
a wide range of different reactor designs (LWR,
HTGR, heavy water reactor). This suggests that
the NNSA has effective internal processes forlicensing facilities using technology-neutral
requirements or on a case-by-case basis.
In China, regulatory approvals are granted to anuclear power plant for different phases or major
milestones in plant construction and operation.
Phases or milestones that require regulatory
review include initial siting, construction, initialfuel loading, initial criticality, operator training, andstart of decommissioning.
At each stage of the regulatory process, theapplicant completes different safety assessment
and verification activities, which are then reviewed
by the regulator to determine whether the specificactivity can be completed safely. The review
determination is based on a number of factors
including compliance with existing regulations andadequacy of nuclear quality assurance programs.
The NNSA was formed in 1984 and was largely
modeled on the laws and regulations present inother countries with established nuclear power
sectors. As a result, the regulatory system in China
in some ways closely resembles the system in
the United States with its emphasis on defense indepth, deterministic analyses, and conservative
assumptions. Despite these similarities, however,the presence of state-owned energy companies
and the absence of significant public and court
challenges to licensing and deploying nuclear
technology significantly change how the NNSA
can review and regulate plants.

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

125

Finding:

Regulatory agencies around the world haveadopted basic principles similar to thosedescribed in the policies of the IAEA and in
U.S. NRC regulations, though they vary intheir detailed application of these policies
and principles—for example, with respect torequired burden of proof. While significant
cultural, social, and political differences may
exist between countries, the fundamental
basis for assessing the safety of nuclear
reactors is fairly uniform among countries
with established nuclear power programs.

Recommendation:

Regulatory requirements for advanced
reactors should be coordinated and aligned
internationally to enable international
deployment of commercial reactor
designs, and to standardize and ensure ahigh level of safety worldwide. National
differences in safety regulations due
to accepted cultural practices make it
difficult to develop a universally accepted
regulatory licensing regime. But certain
basic standards for nuclear safety should
be maintained internationally due to the
far-reaching environmental and social/political effects of nuclear plant operation.
Initial international agreement on specifictopics (e.g., station blackout resiliency) andjoint licensing evaluations could advancediscussions about undertaking reciprocal
reactor design evaluations between
nations or standardizing internationalsafety requirements.

5.5 AN ASSESSMENT OF LICENSINGPATHWAYS IN THE UNITED STATESThe licensing of a nuclear reactor requires
analysis and approval of all features that could
affect safety. These include the facility site, thereactor design, and support facility designs.
The licensing process also requires verification
and approval of the facility’s construction andoperational procedures. Additional reviews andapprovals may be needed to verify the safety ofcontinued operation after initial startup, as well
as safe shutdown and facility decommissioning.
In every country with a commercial nuclear power
program, regulators review all aspects of nuclear
facilities. However, countries differ in how they
conduct licensing reviews and in the degree of
public participation and input they seek during
these reviews.
Licensing pathways can be divided into twogeneral classes: (a) staged processes that
require approval at each phase of facility design,
construction, and operation and (b) one-stepprocesses that provide a single regulatory
approval for all stages of reactor construction andoperation (Figure 5.1). We consider the advantages
and disadvantages of these two approaches tolicensing new commercial power plants in the
United States.

Two-Step Licensing Approach
In the United States, Part 50 of Title 10 of theCode of Federal Regulation (10 CFR 50) provides
the regulatory basis for licensing and regulating
nuclear power plants. It requires that plants
obtain a “construction permit/operating license”(CP/OL) (NRC 2007a) through a two-stepprocess (historically, this process was based on
the process for licensing radio stations under the1934 Federal Communications Act) (Mazuzan andWalker 1985).
First, applicants submit a preliminary safety
analysis report that provides initial details on
the siting, design, and operation of the proposed
reactor. The construction permit application
does not need to have complete informationon the reactor design and site but must provide“reasonable assurance” that, by the end of
construction, the reactor can be operated safely.

126

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDThe construction permit allows the applicant tobegin work but does not provide guarantees thatthe reactor will be licensed to operate.
The application for an operating license issubmitted when the reactor and plant are nearing
completion. This application includes the final
safety analysis report on the site, design, andoperation of the reactor, a physical security planfor the facility, details on safeguards for nuclear
materials, and additional technical details onplant safety features. Staff of both the NRC andthe Advisory Committee on Reactor Safeguards(ACRS), a statutory body of experts that provides
independent technical assessments for the
NRC, review CP/OL applications under the Part
50 licensing process. Public hearings are also
conducted before issuing the CP/OL to allow the
public to provide input or voice objections to the
proposed applications.
The CP/OL model has been used to license allcommercial nuclear reactors constructed andoperated in the United States prior to 2012.

One-Step Licensing Approach
In the United States, Part 52 of Title 10 of the Codeof Federal Regulation (10 CFR 52) provides theregulatory basis for licensing nuclear power plants
using a ‘combined operating license’ (COL) model(NRC 2007e). Under 10 CFR 52, reactors can belicensed for construction and operation in a single
step with optional separate approvals for thereactor design.
Applicants for a COL submit a single license
application (COLA) that contains the same
complete site, design, and operation information
required for an operating license granted under 10
CFR 50. The application also includes ‘Inspections,Tests, Analyses, and Acceptance Criteria’ (ITAAC)
for the specific facility and site (NRC 2007e).
ITAAC are designed to give “reasonableassurance” that the reactor design approved in
the COL application will be constructed correctly.
Instead of having two sets of reviews and public
hearings as required under 10 CFR 50, a single
set of hearings occurs before plant construction
begins. If a plant receives a COL and successfullycompletes all required ITAAC, its operation
is guaranteed and is not subject to additional
hearings. The complete COLA is still reviewed toassure technical accuracy and completeness.
Applicants will often seek a COL after obtaining
a design certification (DC) or standard design
approval (SDA) for a reactor facility or major
portion thereof. In a DC or SDA, applicants seek
approval for the generic design of a reactor facility
or major portion thereof, independent of the site

Figure 5.1 Two licensing processes for new commercial nuclear power plants in the United StatesaInspections, Tests, Analyses, and Acceptance Criteria

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

127

where it will be constructed. The application
for a DC or SDA will contain, depending on thescope of approval, the same level of technicaldesign information that is present in an OL or COL
application, but it will consider facility operation
for a generic site operational envelope insteadof a specific site. NRC staff reviews the DC or
SDA application and works with the applicant
to resolve technical issues before issuing thesafety certification.
Applicants have also sought COLs after obtaining
an early site permit (ESP) for a specific plant site.
In an ESP, applicants seek approval for a reactor
site, independent of the reactor design. Generalreactor design parameters, including reactor size,
number of reactors, typical cooling configuration,and bounding radiological releases, are consideredand evaluated for the geological and hydrologicalfeatures of the specific site. The ESP application
contains the same site-specific informationthat is present in a CP or COL application, but
it considers site suitability for a generic reactor
design envelope instead of a plant configuration.
NRC staff reviews the application and works withthe applicant to resolve technical issues before
issuing the ESP.
The advantage of a DC, SDA, or ESP is that they
provide a designer or applicant with different
levels of regulatory assurance that their design is
acceptable to the regulator and could be approvedfor construction and operation. A DC is considereda final regulatory decision and is not subject toadditional review unless substantial new evidence
is discovered. An SDA is a quasi-final regulatory
decision and regulatory staff is instructed to
avoid additional reviews absent new evidence(NRC 2007e). The DC and SDA are also usefulfrom the standpoint of standardizing reactor
designs: a DC or SDA may be cited by subsequentsite-specific licenses, thereby avoiding the needfor redundant reviews and reducing regulatory
risk and uncertainty. The Part 52 process has beenused to license eleven nuclear reactors in the
United States, two of which (the Westinghouse
AP1000 reactors at the Vogtle site in Georgia) arecurrently under construction.

128

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Licensing and Regulatory Support Processes
The COL approach was created in 1989 in the
United States and was intended to improve thelicensing process for new reactors by reducing
the number of hearings and approvals required
and by guaranteeing that a reactor that receives
a COL can operate (assuming all ITAAC aresatisfied) (NRC 1989). Prior to 1989, reactors
could be granted a construction permit, complete
construction, but have facility operation delayedby several years due to regulatory and public
legal challenges related to the issuance of theoperating license (Walker and Wellock 2010).
While the COL process requires applicants tohave complete design and site information years
before construction begins (increasing the timeand investment required before construction can
begin), it increases the likelihood that a plant will
operate after significant capital investments are
made. The COL approach is optimal for reactor
designs that have high design maturity (due to thetechnical information required as part of the DC
or SDA approval process) and high operational
maturity (standardization limits a designer’s ability
to make changes on subsequent reactors basedon lessons learned from experience with operatinga first reactor), or in cases where designers orowners intend to build in multiple locations (dueto the regulatory costs borne by the applicant forcompleting the DC or SDA approval process).
Licensing activities for new reactors are notlimited to formal reviews of license applications
for specific reactor facilities or reactor designs.
Applicants can receive regulatory feedback on avariety of subjects based on their specific licensing
strategy and project needs. Common regulatory
feedback processes include:• Pre-application meetings and discussions tofamiliarize staff with the applicant’s licensing
strategy and design.
• Informal regulatory review and feedback on
general reactor design features or formal
review and approval of specific design andanalysis methodologies.
• Formal review and approval of a proposed
reactor site before the submission of a CP or
COL application.

Table 5.2 summarizes the wide range of regulatory
support processes that is applicable to newreactor licensing. These additional feedback
processes are valuable because they allow
applicants to resolve technical issues before
submitting formal applications, avoiding alengthy formal application amendment process.
Pre-application meetings and informal review ofa prospective design help ensure the regulatory
staff has sufficient familiarity with the proposed
design to perform an efficient licensing review. The
NRC’s staffing costs to support these regulatory
feedback processes are paid by applicants on
an hourly basis (NRC 2017a). Nevertheless,the interactions are generally recommended tofacilitate a more efficient review and are now being
used more extensively.

Proposed Licensing Strategies for
New Reactors
Interest in advanced nuclear reactors has led
different industry and government groups to study
and propose new strategies for reactor licensing.
These strategies address the applicability ofcurrent licensing processes to advanced reactors(including both LWR and non-LWR designs) andthe need for processes that better align withtimelines for advanced reactor deployment.
The strategies proposed by industry organizations
vary from modified applications of existing
regulations to the creation of entirely new
licensing frameworks for advanced reactors.
Use of a staged licensing approach with smaller,
more frequent regulatory approvals using existing
regulation has been proposed by the Nuclear
Innovation Alliance (Finan 2016). This approachis designed to provide greater transparency in thelicensing process for companies and investors
while allowing for more direct feedback between
regulators and applicants. A Nuclear Infrastructure
Council white paper also emphasized the needfor a staged licensing process together with theimplementation of non-LWR-specific design
criteria (Merrifield 2016). Such an approach is
discussed in the next section.

Led by Southern Company, an industry group
has proposed new regulatory frameworks. The
Licensing Modernization Project has sought toidentify regulatory gaps that must be resolved tosupport the licensing of non-LWR designs undercurrent regulations. This effort seeks to enable
regulatory frameworks that are risk-informed,
performance-based, and technology-inclusive.
The Licensing Modernization Project intends tosubmit white papers for NRC approval on threedifferent topics: risk-informed licensing basis event
selection, PRA technical adequacy evaluation
processes for licensing basis event selections, and
PRA technical adequacy evaluation processes
for risk-informed, performance-based regulation(Nuclear Energy Institute 2017).
Recognizing public and industry interest inadvanced reactor licensing, the NRC has
proactively developed policy positions and earlyguidance on this topic (NRC 2012) (NRC 2017b,c, d). The NRC guidance is largely focused on
generic design criteria for advanced reactors andrequirements, and not on overall licensing strategy.
As part of the Next Generation Nuclear Plant(NGNP) program, the U.S. Department ofEnergy (DOE) and the NRC jointly publisheda licensing strategy document in 2008. The
strategy document identified potential licensing
strategies for an advanced reactor design andoutlined potential changes to NRC licensing
frameworks that could be used to accelerate
licensing (U.S. Department of Energy and U.S.
Nuclear Regulatory Commission 2008). Though
the NGNP program did not move forward withefforts in this area, DOE continued work on
advanced reactor licensing. The 2016 DOE
Advanced Reactor Option Study (Petti, et al.
2017) described licensing pathways for different
advanced reactors based on level of technologicalmaturity and reactor license type (i.e., commercial
power reactor, commercial prototype reactor, test
reactor, research reactor). All pathways relied on
existing, available regulatory tools and minimized
new NRC decisions.

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

129

Table 5.2 Supplementary NRC Licensing Processes
Process

Objectives

Examples

Early Site
Permits (ESP)(a,b)

Formal NRC review and certification of the acceptability of a specific site for the construction andoperation of a nuclear power plant. The ESP focuses on the overall site characteristics (seismic,
meteorological, hydrological, and geologic), surrounding populations and areas, and evaluates
whether the site would be acceptable for a reactor of a generic specified design.

ESPs have been issued for
Clinton, Grand Gulf, North
Anna, Vogtle, and the PSEG
site near Salem and Hope
Creek Plants.

Formal NRC review and certification of the safety and acceptability of a reactor design for ageneric site as well as the ability of an applicant to manufacture, transport, and install the reactor.
The ML includes full approval of the reactor design and thus requires all of the same technicalinformation required in an OL or COL final safety analysis report related to the design of thereactor. The ML approves the applicant’s ability to manufacture and transport the proposed reactor
with sufficient quality assurance, the site parameters required for installation of a reactor, and therequired interface conditions between the manufactured reactor and the remainder of the plant.

In 1982, a ML was issued toOffshore Power Systems, areactor designer that intended
to construct offshore floating
nuclear power plant.

Standard Design portion is historically defined in terms of complete system sets (e.g., nuclear island, nuclear
steam supply system, turbine island, balance of plant system). The SDA approves the design andApprovals (SDA) operation of a portion of a reactor design and thus requires all of the same technical information

Formal NRC review of the safety and acceptability of a reactor or major portion thereof. Major

required in an OL or COL final safety analysis report for the specific portions covered in the SDA.

SDAs have been issued
for entire reactor systems
including ESBWR, ABWR,
AP600, AP1000, and CE
System 80+.

Standard Design
Certifications(SDC)

Formal NRC review and certification of the safety and acceptability of a complete reactor system.
The SDC approves the design and operation of a portion of a reactor design and thus requires allof the same technical information required in an OL or COL final safety analysis report.

SDCs have been issued for
the ESBWR, ABWR, AP600,
AP1000, and CE System 80+.

Limited Work
Authorizations

Formal NRC review and approval to begin limited site preparation and construction of portionsof safety related building prior to receiving a CP or COL. The authorization requires descriptionof all tasks to be completed as well as safety and environmental evaluations of those tasks. The
applicant performs the work at risk because the work is completed while the application is still
under review and technical details of the project may be subject change.

Limited work authorizations
have been issued for anumber of projects for sitecharacterization and site
preparation.

Pre-Application
Meetings

Informal NRC communications, correspondence meetings, document submittals/reviews, andother interactions that occur before formal submittal of licensing applications. Pre-application
meetings can provide early identification of regulatory requirements, development of resolution
paths for open policy, technical and licensing issues, and increased staff familiarity with designspecific issues to help increase the stability and predictability of the licensing process and reducetime required for review of the formal license application. Pre-application meetings can begin atany point and meeting content will vary significantly on an applicant-by-applicant basis.

These meetings have beenused by all reactor design
applicants to help explain thesystem to regulators and get
initial and informal regulator
feedback on submission
materials.

White
PapersInformal NRC review of reports that address and document an applicant’s position on
specific technical or regulatory issues facing the project. White papers are intended
to increase NRC staff understanding of technical or regulatory issues; no formal staff
review of the paper is published.

White papers were used toclarify the safety approach in
the NGNP gas-cooled reactor
system concept.

Technical
Reports

Informal NRC review of reports that provide supporting or supplemental informationon technical safety topics in license applications. The technical reports may containdetailed technical information or testing data that support statements or conclusions
made in the license application or they may provide more detailed discussion of
application-specific methodologies. NRC staff may issue formal questions but will not
publish a safety evaluation on the content of the technical report; instead, NRC staff
evaluation of the report will be included with the evaluation of the license application.

This is a common approach
used by many reactor design
applicants to explain detailsof their safety analyses; e.g.,
LOCA safety analyses.

TopicalReports

Formal NRC review and approval of technical topics related to nuclear safety that will
apply to multiple applications or licensees. Topical reports allow for a single review ofa broader technical issue separate from a specific application review; this is intended
to increase regulatory efficiency and consistency. NRC staff may issue formal
questions and will publish a final safety evaluation on the contents of the topicalreport that can be referenced in subsequent applications as precedent.

Topical reports have been
issued as part of the design
certification for novel reactor
protection systems andelectrical system designs.

Manufacturing
Licenses (ML)(a,b)

Additional
Document
Reviews

 pplicants for supplementary processes can be submitted independent of a CP/OL or COL application and can be submitted beforeAother applications.
b	Approval of information is considered final and is not subject to re-review if the valid application is referenced and substantial changes or
new information has been discovered that could invalidate the original findings.
a130

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDCreating new regulatory tools—such as a
new ‘Part 53’ licensing process for advanced
reactors—through formal rulemaking would takeseveral years and probably would not result ina process that actually expedites licensing (seeSidebar 5.2). The NRC should instead continue towork with applicants to prepare project-specificlicensing plans that describe the specific licensing
processes and timelines that an applicant can
expect to use to license a new reactor. Early
discussion and consensus on a licensing plan
would be the most effective way to utilize NRC
staff and applicant resources to complete licensing
using existing regulatory processes. Creating a
new regulatory agency specifically for the purposeof licensing advanced reactors would require
substantial efforts by Congress and the executive
branch, such as amending the Atomic Energy Act
or passing new legislation and rulemaking. The
political capital and focus necessary for theseactions seems unlikely to materialize given current
political priorities.
The optimal licensing strategy for new reactor
designs, especially advanced reactor designs, willvary significantly based on the reactor technology,
its design maturity, and the business model
being used. Various proposals by regulatory
agencies, industry groups, and non-governmentalorganizations have suggested different pathways
that could be used to license new designs
and facilities. These pathways and strategies
demonstrate that licensing can be accomplishedusing existing regulatory processes such as topicalreports, standard design approvals, standard
design certification, and either Part 50 or Part 52
licensing (see Figure 5.1).
Finding:

A wide variety of pathways and strategies
are available for licensing new reactors(including advanced reactors) in the
United States. These include using existing
regulatory processes such as topical reports,
standard design approvals, standard design
certification, and either Part 50 or Part
52 licensing.

Recommendation:

While current regulatory structures havesufficient flexibility to allow for technologyor reactor-specific licensing pathways, theU.S. NRC should continue to move toward
the use of performance-based and riskinformed design criteria for new reactors.

The NRC should work to endorse and implement
the use of risk-informed and performancebased design criteria to license new reactors
within the current regulatory framework. Useof modern risk assessment techniques can
expedite regulatory reviews and focus the
allocation of staff and applicant resources. Useof performance-based criteria will be valuable
when reviewing new reactor designs that employ
innovative approaches to safety that are not welldescribed by current regulation. The combinationof risk-informed and performance-based design
criteria will provide the greatest flexibility for bothdesigners and regulators in the licensing of new
nuclear power plants. Additionally, future design
criteria should be written in a technology-neutral
matter to ensure their applicability to all advanced
reactor types. Use of technology-specificrequirements will likely be appropriate in specificinstances to reduce regulatory uncertainty. An
individual applicant or groups of applicants(utilizing similar reactor technology) could
then develop technology-specific requirements
in coordination with the NRC as a part ofpre-licensing interactions.
Although NRC staff has developed both policy
positions and early guidance on portions of theadvanced reactor technology licensing process,uncertainty remains with respect to licensing andcommissioning an actual advanced reactor facility.
The process difficulties encountered by applicantsand NRC staff during the licensing of evolutionary
LWR designs in the early 2000s led to further
concerns about the ability to expeditiously andefficiently license an advanced reactor design.
License applications that were missing criticaltechnical details and frequent design changes
by applicants reflected the industry’s lack of

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

131Sidebar 5.2: Creating New Regulatory Tools
Creating new regulatory tools in the United States cantake significant time due to the need for legislative
authority, U.S. Nuclear Regulatory Commission (NRC)
direction, NRC staff action, and public involvement. The
figure below outlines the typical steps required for major
NRC rulemakings absent legal challenges or advancenotices of proposed rulemaking. The rulemaking process
for Part 52 of Title 10 of the Code of Federal Regulation(10 CFR Part 52) provides insights into the steps and timethat would be required to develop new regulations forlicensing advanced reactors.
Figure 5.3 Typical NRC rulemaking process
NRC rulemaking initiated by
Congress, Commission, or Public

NRC Commissioners
review and approverulemaking plan

Regulatory basis
drafted by Staff,
public meetings held

Regulatory basis forrulemaking finalized
and published

Draft rule published
for public comment
in Federal Register

NRC Commissioners
review and approve
Staff’s draft rule

Public input on draft
rule sought fromstakeholder groups

Public comments
incorporated by
Staff into draft rule

NRC Commissioners
review and approve
Staff’s final rule

Final rule publishedin Federal Registerwith rule guidance

Final rule takes effect(U.S. Nuclear Regulatory Commission 2017f)

The creation of 10 CFR Part 52 was preceded by morethan a decade of NRC efforts to develop rules forplant standardization based on existing regulations
and on several unsuccessful proposals to Congressfor authorization to modify the licensing process(NRC 1987) (NRC 1988) (NRC 1989) (United States
Court of Appeals 1992). The formal rulemaking process—including announcement of intent to issue rules, issuanceof proposed rules, and issuance of final rules—took
approximately 18 months (from September 1987 to April
1989) (NRC 1989).
Legal challenges continued for several years after as
the courts decided whether the NRC had the statutory
authority to promulgate the new rules (United States
Court of Appeals 1992). Passage of the Energy Policy
Act of 1992 amended sections of the Atomic Energy Act
and provided explicit statutory authority for the Part 52
licensing process (Energy Policy Act 1992).

132

In December 1998, the Commission agreed to an NRC
staff proposal to fully revise and clarify Part 52 throughadditional rulemaking (NRC 2003). Over the next fourand a half years, NRC staff discussed and revised draft
rules with public and industry stakeholders. The NRC
issued the updated 10 CFR Part 52 as a proposed rule in
July 2003 for public comments but halted rulemaking
when public comments led NRC staff to decide thatfurther revisions were required. NRC staff madesubstantial revisions and issued a new proposed rule forpublic comment in March 2006. After incorporation of
final comments, the rewritten 10 CFR Part 52 was issued
as final rule in August 2007 (NRC 2007g). The firstcombined operating license granted under Part 52 was notissued until February 2012.
While the time required to complete the formal
rulemaking for 10 CFR Part 52 was limited to between 12
and 18 months for each major revision, the Commission
and NRC staff required substantial lead time to prepare
for rulemaking and include public comment. The
provisions of 10 CFR Part 52 represented a significant
paradigm shift in U.S. reactor licensing and substantial
time for rule revisions was needed to produce a functional
rule even after the final rule was initially promulgated.
More generally, new regulations very typically require
additional time for the passage of authorizing legislative
amendments and to resolve legal challenges, as applicable.
An effort to create new regulatory tools for the licensingof advanced reactors could take more than a decade,especially if the tools significantly depart from regulatory
precedent. Smaller changes, such as clarifying existing
NRC rules for advanced reactors, could likely be
accomplished much more rapidly. Finally, internal policychanges from the Commission or revisions to NRC
staff guidance on licensing issues can clarify advanced
reactor licensing options without resorting to formal
rulemaking. While formal new rules for non-LWR designs
could reduce licensing times in the future, it is not clearthat substantial schedule benefits could be gained fromstarting the rulemaking process before there is more ofan experience base with commercial advanced reactors in
the United States.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDexperience with the Part 52 licensing process
and its difficulty understanding NRC staff
expectations. The limitations of initial regulatory
guidance on issues such as license application
technical content or resolution processes forcomplex technical issues only became clear once
the Part 52 licensing process was used to license
evolutionary LWR designs (NRC 2013).
Recommendation:

In the United States, the NRC should test
its advanced reactor licensing process inthe next few years to identify unanticipatedlicensing hurdles and to train NRC staff.

While internal readiness reviews and otherpre-application activities can help prepare
applicants and NRC staff to license advanced
reactor designs, actual experience with anadvanced reactor design is necessary. Lessons
learned from licensing the first non‑LWR advanced
reactor design will likely be pertinent to all later
applicants and will be invaluable in optimizing
regulatory procedures to ensure an efficient andeffective licensing process. Partial government
funding of a lead advanced reactor licensing effort(similar to the abandoned NGNP licensing effort)(U.S. Department of Energy and U.S. Nuclear
Regulatory Commission 2008) could be used to
improve the regulatory process in preparation
for licensing privately funded advanced reactor
designs. This policy issue is discussed in
Chapter 4.

Phased Licensing Approaches
The concept of fixed licensing periods and costs
closely relates to existing proposals for a phased
licensing approach that breaks the process ofregulatory decision making into several smaller,
discrete steps (Finan 2016). When going throughthe Part 50 or Part 52 licensing process, applicantsreceive two or one formal regulatory decisions,
respectively (CP/OL or COL). The rationale fora phased approach is to provide more frequent,
limited milestones related to the licensing process,each of which provides incremental approvals of

the design. Instead of spending several years in
the licensing process for a construction permit
or design certification, applicants could get
preliminary approval on smaller portions of thedesign (e.g., the emergency core cooling system)
more quickly and at lower cost.
Phased licensing approaches for advanced
reactors have several distinct advantages,
especially for companies pursuing highly
innovative designs or business models such asstaged venture capital funding. Formal regulatory
evaluation of small portions of a design allows
applicants to prioritize the review of criticalsystems or systems with high regulatory risk. Early
regulatory feedback on these systems can help
applicants assess the commercial viability of adesign more accurately and inform their decision
about whether to proceed with reactor licensing,potentially saving millions of dollars and yearsof effort if they were considering an infeasible
or difficult-to-license design. A phased licensing
review also provides greater transparency as
applicants move through the licensing process.
Formal approvals on portions of a design give
applicants tangible insights about their progress
through the regulatory process and a ‘citable’
metric that could be used to strengthen theirbusiness case when they solicit additional funding
from investors to complete the licensing process.
While a phased approach provides flexibility,
extensive use of a phased approach could
introduce additional time and cost in the processof advanced reactor licensing. A significant
challenge is the finality of regulatory decisions ina phased review. Nuclear power plant systems
are highly interconnected: the design adequacyof one system depends heavily on boundary
conditions or inputs from many other systems.
The safety evaluation for a smaller portionof a plant may depend heavily on the design
and performance of related systems. In thatcase, it may not be possible to reach a final
regulatory decision until all related systems areevaluated together. A phased approach may
provide formal feedback along the way, but thesystem being reviewed cannot be considered‘approved’ until all related systems have been

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

133

reviewed and potentially integral effects havebeen evaluated. This additional uncertainty
about final approval can introduce schedule andcost risk into the licensing process. Additionally,
the use of a phased approach could slow theprocess because the phases of the review would
proceed in series, rather than in a parallel fashion.
In sum, phased licensing may increase process
flexibility, but it would likely also increase thecost, time, and uncertainty involved in licensing an
advanced reactor.
Because the NRC already has the regulatory
tools in place to implement a phased licensing
approach, no new formal regulatory processes
are needed. Different regulatory processes can beused depending on methodology, design feature,or system under consideration and the level offinality desired in the regulatory evaluation.
Staff evaluation of applicant reports (such as the
topical reports noted in Table 5.2) can provide
applicants with feedback regarding design
methodology and features, but such evaluations
would not be considered formal licensing
documents. SDAs can be used to obtain formal
licensing approval of major portions of the reactor
plant without submitting a full plant design
for approval.
Finding:

In the United States, the NRC currently
has the regulatory processes available toimplement a phased licensing approach foradvanced reactors—thus no new formal
regulatory processes are needed. Use ofphased licensing processes, however, may
increase the total cost, time, and uncertainty
related to advanced reactor licensing.
Applicants must determine on a case-bycase basis which licensing approaches best
suit their project and should work with the
NRC to create design-specific licensing
plans that use the most appropriate set of
regulatory tools to achieve desired outcomesfrom the licensing process.

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THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Licensing Processes for Prototype, Test, andResearch Reactors
Licensing new reactor designs can be challenging
if there is insufficient commercial operating
experience to validate the design or performanceof safety systems. Where operating experienceis lacking, safety systems can be validated
via separate and integral effects testing or via
demonstration using a prototype reactor. Whilesome tests can be performed in laboratories
without nuclear fuel (such as verification of flow orheat transfer conditions), other tests (such as test
validation of fuel feedback effects) will require theuse of a full-size or reduced-scale nuclear reactor(NRC 2017e). The validation of critical safety
features for innovative designs that have notamassed significant operating experience will thus
likely need to be accomplished through the use of
prototype, test, or research reactors. In this section
we discuss licensing definitions, requirements, andpathways for prototype reactors. Prior sections
have detailed the impact of reactor prototypes ontechnology development (Chapter 3) and businessconsiderations (Chapter 4).
The terms ‘prototype,’ ‘test,’ and ‘research’ have attimes been used interchangeably to describe thefirst reactors constructed using a new design. The
terms ‘first-of-a-kind’ (FOAK) and ‘demonstration’
have also been used to describe such reactors. Eachof these terms, however, defines a specific type ofreactor or reactor license. Their formal definitions
from a regulatory perspective are as follows:• Prototype reactors are non-commercial orcommercial reactors that use novel design
features and have additional safety features toaccount for uncertainty related to their design.
• Test reactors are larger non-commercial reactors(in the sense that less than 50% of theiroperating costs are recovered by commercial
activities). Any non-commercial reactor withpower levels above 10 megawatts of thermal
output (MWth) or with power levels above
1 MWth that uses novel design features isclassified as a test reactor.

• Research reactors are small non-commercial
reactors (less than 50% of operating costs
recovered by commercial activities). They
must have power levels below 10 MWth to beclassified as a research reactor or below 1 MWthif they have novel design features.
• FOAK reactor has no formal regulatory
definition, but the term ‘FOAK’ generally refers
to any reactor that is the first commercial unitof that design to be constructed.
• Demonstration reactors have no formal or official
regulatory definition.
Previous non-LWR designs have been categorized
into these reactor types depending on reactor
size, whether they were operated as commercial
or non-commercial facilities, and the novelty of
their design.

Part 50 or 10 CFR Part 52 but due to engineering
uncertainties in the design and operation of areactor with novel design features, the NRC “mayimpose additional requirements on siting, safety
features, or operational conditions” in the case ofa prototype reactor (NRC 2007a). Since provisions
for a prototype reactor were added to NRC
regulations in 2007, no applicant has attempted
to license such a reactor but there has beenrenewed interest in using the prototype reactor
licensing process to license advanced reactors,
and in fact this is the approach we recommended
in Chapter 3 for the less mature Generation-IV
reactors. In 2017, the NRC published the first in aseries of staff white papers providing preliminary
staff positions and guidance on the licensing of
prototype reactors (NRC 2017e).

Prototype Licensing

Research and test reactors can be licensed
under either 10 CFR Part 50 or 10 CFR Part 52.
The process is the same as that for commercial
reactors, but Section 104(c) of the Atomic
Energy Act directs the NRC to “impose only suchminimum amount of regulation” to protect the
public and to “permit the conduct of widespreadand diverse research and development” (Atomic
Energy Act of 1954). The NRC has publishedguidance on license applications for researchand test reactors in NUREG-1537 and many ofthe best practices from commercial licensing(pre-application interactions, licensing plans,etc.) are also applicable to the efficient licensingof research and test reactors (U.S. Nuclear
Regulatory Commission 1996). The novel design
features that can distinguish such reactors
include circulating loops for fuel testing orin-core experimental facilities over a certain size
(NRC 2007a).

The NRC should begin developing licensing
strategies for prototypes of advanced reactor
designs. U.S. nuclear regulations in the 1950s
and 1960s permitted the design, construction,and operation of a wide range of nuclear
technologies. As noted earlier, four main safety
principles—engineering margin, lower reactor
power, containment, and remote siting—characterized these early regulations (Walker andMazuzan 1992).

Limited regulatory guidance and no historicalprecedent exist for the modern licensing of
prototype reactors. The addition of 10 CFR
50.43(e) to NRC regulations in 2007 was intended
to open the door to prototype reactor testing as an
acceptable method for demonstrating the safetyof novel design features (NRC 2007f). A prototype
reactor can be licensed under either 10 CFR

Applicants with innovative reactor designs would
not need to make a full, a priori demonstrationof reactor safety. Rather, they could use theprototype reactor to generate needed engineering
data and operating experience, and to conduct the
integral testing required to license the next reactor
based on the prototype design. This change could
significantly reduce the time required to license a
prototype reactor.

Application of these four safety principles canprotect public health and safety independent of
the specific reactor technology being considered(LWR or non-LWR) and can reduce accidentrelated risks by limiting the radiological source
term and the consequences of an accident if one
were to occur. These safeguards may also reducethe burden of proof required in license applications
and expedite prototype license reviews.

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

135

A licensing strategy for prototype reactors canhave the following attributes (Figure 5.2):• Conservative design margin – Designcomponents and systems with additional
engineering margin (beyond that requiredby consensus codes and standards) to help
compensate for uncertainties related tooperation or other physical phenomena.
• Power ascension – Limitation on the initial
reactor power and/or radionuclide inventory
to limit radiological release source term
during testing. Power ascension programs
could be used to reach final rated power given
successful testing.
• Functional containment – Use of structures,
systems, and components that can limit
radiological releases, mitigate off-site
consequences, and satisfy defense-indepth principles.
• Acceptable siting – Sufficiently large siteboundaries and/or siting away from population
centers to minimize the potential for public
exposure during operation and testing.
Figure 5.2 Conceptual Picture of Prototype
Safety Attributes
Acceptable Siting

development in new nuclear technologies. The
regulator would need to agree on the conditions
or analyses required to be completed before
additional prototype reactor safety features could
be removed. This would help ensure that safety
features added to account for uncertainty in the
prototype are not required on subsequent similar
plant designs.
Another consideration is that a company may
choose to build and test prototype reactors
outside of its market territory for strategicor economic reasons—for example, testing
reactors in Canada for sale in the United States(see Chapter 4). If a regulatory authority otherthan the NRC oversees prototype testing andlicensing for a reactor design that will be sold in
the United States, the results of the prototype
testing must still meet NRC requirements. In
that case, applicants must work with the NRC
before prototype construction to ensure that the
prototype test program will satisfy all applicableregulatory requirements. Specifically, data fromthe test program must meet NRC requirements fornuclear quality assurance (NRC 2017e).

Finding:

The U.S. NRC’s prototype rule can provide analternative pathway for licensing advanced
nuclear reactor designs.

Functional
Containment

Recommendation:
Power
Ascension

DesignMarginUnder this process, applicants could design andconstruct prototype reactors using a reactor
technology with innovative features. With theattributes described above, the new process
could accelerate early-stage research and136

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDThe U.S. NRC should clarify its prototype
rule and licensing pathway to allow for
more rapid licensing of prototype reactors
without excessive regulatory burden. While
additional safety features may be required
to license a prototype reactor, regulatorsand license applicants should agree toconditions (experimental tests and data)that would allow for these features to be
removed in future plants. The prototype
licensing pathway should be available to all
reactor technologies.

Codes and Standards
The NRC relies in part on consensus codes andstandards for the licensing and regulation ofcommercial nuclear activities. It incorporates such
codes and standards into regulation by endorsing or
approving the use of designs, codes, and standards
created by industry groups, such as the ElectricPower Research Institute (EPRI), or standards andprofessional organizations, such as the American
Society of Mechanical Engineers (ASME), theAmerican Concrete Institute (ACI), and theAmerican Nuclear Society (ANS). These individual
groups and organizations control the drafting,updating, and revision of all consensus codesand standards. In the United States, the federal
government is required by law to use consensus
codes and standards where appropriate to reduce
duplicative work by taxpayer-funded agencies
and to promote uniform adoption of standards(National Technology Transfer and Advancement
Act of 1995 (1996)). Reliance on consensus
codes and standards also allows the NRC tocollaborate closely with groups of independent
subject matter experts to determine appropriate
design requirements and methods for commercial
nuclear activities.
While the NRC’s use of consensus codes andstandards has resulted in the safe design andoperation of nuclear power plants to date, there
is a need to re-examine the cumulative impactof these codes and standards. In the past,consensus codes for specific types or classesof structures, systems, and components (SSCs)
were developed independently by different
organizations: for example, Section III of the
ASME code for boilers and pressure vessels
provides rules for the design and construction ofpressure-retaining components and supports. As
a result, the interactions between different codes(e.g., ACI’s civil design codes for a building and
ASME’s mechanical design codes for a building
component) within possible event sequences
have typically not been explicitly examined.
Conservative interface conditions are normallyassumed but these assumptions are made at thediscretion of the code committee. The overallsystem effects or event sequence consequencesof these code interactions should be reviewed,

since event sequences rarely involve a single typeor class of SSC. For example, a component witha high design margin cannot perform its safetyrelated function if the low margin structure it islocated in has collapsed.
Inconsistent requirements with respect to design
margin under different codes and standards canresult in the relative under‑design or over‑designof components. Individual consensus committees
determine acceptable levels of safety based on
the design philosophy particular to their practice.
While the process results in codes that reflect
an individual profession’s definition of safety, theoverall safety of the plant depends on interactions
between these codes. Reviewing and aligningdefinitions of safety and design margin between
different consensus codes and standards would
have several important benefits:• Harmonizing design margins could allow
for reductions of excess margin in some
types of SSCs where the safety benefits ofthe extra margin are never realized because
other components would fail first in the event
sequences of concern. Lower design margins
could produce cost savings in the manufactureof some components or provide greater
flexibility during operation. Harmonization
could also result in increased design margins
for some components, to ensure they do notdisproportionately contribute to the risks
or consequences associated with a given
event sequence.
• Reviewing design margins in consensus
codes could help address the phenomenonof gradual but continuous increases in safety
requirements, commonly described as a
‘ratcheting’ of safety requirements. Explicitly
quantifying the sources and rationale for design
margin in codes and standards can be used toquantify the current safety of components andidentify gaps or overlaps in design codes that
could be resolved. Elimination of unneeded
design requirements or margin could havesignificant impacts on cost and operations.

Chapter 5: Nuclear Reactor Safety Regulation and Licensing137• Aligning the design margins contained
in independent consensus codes andstandards and in NRC rules could prompt
larger discussions about assuring systemsafety and understanding system behavior
during event sequences. Because nuclear
power plants are not composed of isolated
systems, system interactions are critical. For
this reason, explicitly discussing the impactsof design margin on system performanceis important to ensure the overall safety ofplant operation, especially in off-normal or
emergency conditions.
For example, studies of seismic codes havedemonstrated that significant excess margin
could be identified in existing codes. Thus, it ispossible that consensus codes could be updated
to remove or clarify required design margins(Budnitz and Mieler 2016). Such a review process
could be extended to the major consensus codesand standards used in designing and constructing
nuclear power plants. Larger discussions about theinteractions between different consensus codes
and about opportunities to standardize design
margins across codes would likely need to be
initiated by both industry groups and the NRC.
Finding:

Inconsistency in the design margins requiredby different codes and standards can result
in relative under‑design or over‑design ofstructures, systems, and components.

Recommendation:

Consensus codes used in the design andconstruction of nuclear power plants
should be re-evaluated in terms of theirefficacy in ensuring safety. The nature ofsystem interactions in advanced reactor
designs may fundamentally differ frompreviously operated reactor designs. Existing
consensus codes should be reviewed sothat overlapping standards are properly
harmonized. This harmonization willboth reduce the regulatory burden andhelp ensure safe operation for advanced
reactor designs.

5.6 CHALLENGES TO ADVANCEDREACTOR LICENSING COST
AND SCHEDULE
One of the most often cited barriers to licensing
advanced reactor technologies is the cost andtime associated with the licensing process (Finan
2016) (Merrifield 2016). Previous efforts tolicense reactors in the United States, whether
under 10 CFR Part 50 or under 10 CFR Part 52,
took longer than initially anticipated andincurred higher-than-expected regulatory costs(NRC 2015). Historically, licensing costs (i.e., fees
billed by the NRC to the license applicant) havebeen on the order of $100 million for a complete
design certification review and $25–$50 million
for a site-specific combined operating license(NRC 2015). Typically, applicants have also
incurred additional costs to complete the design
work required for a license application and torespond to NRC staff questions on the application.
Chapter 4 discusses the business implications ofadvanced reactor licensing costs.
The NRC has recently planned for a 42-monthprocess to review two specific reactor designs: theKorean APR1400, a large Generation-III+ PWR,
and the NuScale small modular reactor (SMR), an
integral PWR with several novel features that pose
policy issues for LWRs (Akstulewicz 2017). Basedon previous experiences (see Sidebar 5.3), there
is some uncertainty as to whether the planned
42‑month review timeline can be met.

138

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDSeveral topics will need to be considered withrespect to the licensing process for advanced
reactors in the United States:• License application quality, completeness ofdesign, applicant design validation by test or
analysis, and applicant–regulator interactions.
• Duration, cost, and uncertainties of thelicensing process.
• Guidance for regulatory staff on efficient
processes for resolving technical questions
raised during license application reviews.
• Final resolution of policy issues before
submissions of license applications.
• Appropriate NRC and senior management
oversight of regulatory staff performing
licensing reviews.
• Implementation of nuclear quality assurance
programs and requirements• Potential design and operational impacts ofrevisions to radiation health effects models.
If issues arise in connection with any of the above
topics, they will likely result in schedule delays
and increased costs associated with the licensing
process. Additionally, detailed clarification oflicensing rules related to prototype reactor designs
will be critical if applicants decide to license theirfirst commercial reactors as prototypes.

Regulatory Preparedness for Advanced
Reactor Reviews
Regulatory staff must be available and trained
to ensure that applications can be appropriately
reviewed. In the United States, the NRC hasstressed the importance of “the right numberof people with the right skills at the right time”(Fitch and Weber 2015) as it seeks to refocus its
resources on advanced reactor licensing throughProject Aim. This effort is challenging given the
fast-moving nature of startups and newly formed
reactor design companies, the technologicaldiversity of reactor designs currently being
pursued (e.g., high temperature gas, molten-salt,
sodium, lead and gas fast reactors), and the NRC’s

Sidebar 5.3: Cost Increases and Schedule Delays for
Advanced Reactors
In the United States, the design certification review process laid out
in Part 52 of Title 10 of the Code of Federal Regulation (10 CFRPart 52) has resulted in significant delays for reactor designs thathave already been licensed, and, in some cases, constructed, inother countries. Such delays (which have been caused, in part, byboth applicants and regulators) may cause companies to choose
not to complete the licensing process in the United States.
For example, the EPR was docketed for design certification in2007 after nearly three years of pre-application interactions.
At the time the license application was submitted to the U.S.
Nuclear Regulatory Commission (NRC), the EPR was alreadyapproved and under construction at the Olkiluoto site in Finland
and the Flamanville site in France. The project initially had a 38
month review timeline with the Final Safety Evaluation Reportscheduled for release in 2011. By 2013, the timeline had extended
to 80 months with the Final Safety Evaluation Report scheduled
for release in 2015 due to challenges (technical and regulatory)
encountered during the review. NRC reviews continued (withouta public updated schedule) until February 25, 2015 when Areva
formally requested that the EPR review be stopped without
receiving design certification. In total, Areva paid over $82
million for the incomplete review and never completed thelicensing process for the EPR in the United States.
The Mitsubishi APWR was docketed for design certificationin December 2007 after nearly two years of pre-applicationinteractions. At the time of application submittal, the APWR was
already undergoing a licensing safety evaluation for two units at
the Tsuruga site in Japan. The project initially had a 45 monthreview timeline with the Final Safety Evaluation Report scheduled
for release in 2011. By February 2013, the timeline had doubled
to 93 months with the Final Safety Evaluation Report scheduled
for release in 2015 due to challenges (technical and regulatory)
encountered during the review. On November 5, 2013,
Mitsubishi formally requested that the APWR review be stopped
without receiving design certification. In total, Mitsubishi paid
over $86 million for the incomplete review and never completed
the licensing process for the APWR in the United States.
Advanced reactor designs could also be delayed by uncertainties
related to design and technology. Recognizing this concern,
applicants and regulators have begun taking preemptive action
to mitigate the risk of such delays. These actions include
initiating early interactions between applicants and regulatory
staff, ensuring that adequate design and technical resources
are made available, and communicating more clearly aboutschedule, questions, and technical expectations. In a notabledemonstration of the success that can be achieved with theseapproaches, the Korean APR1400 was reviewed and is expected
to receive its design certification with no delays from the original
certification schedule.

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

139

funding limitations. While the first two challenges
could be overcome given sufficiently large
regulatory staffs, the cost and inefficiency of hiring
staff to prepare for every potential application
would be impractical (see Sidebar 5.4).
New business models for reactor development(e.g., venture capital funded startups) often
have short timelines (one to five years) that
require more rapid regulatory decision-making
to be commercially viable. Regulatory agencies
may be unable to accommodate sudden
requests for extensive regulatory review so earlycommunication about expected review scope andschedule is critical for their workload planning. It
is also important to note that this communicationis only valuable if it is accurate. Applicants’estimates of scope and schedule must be realistic
and applicants’ interactions with regulatory staff
must not be used as a marketing tool with theaim, for example, of signaling commercial viability
using idealized and unrealistic schedules.
As noted previously, the wide range of reactor
technologies currently under development bydifferent companies presents a challenge in termsof regulatory readiness. The cost of developing
and maintaining a full regulatory staff to review
reactor technologies that may never be built is
not currently justifiable, so regulatory agencies
must selectively hire, train, and maintain staffing
based on credible information from industry about
potential license applications. Early, frequent,and accurate communication (several years inadvance) from companies regarding their plans
to apply for licenses is extremely valuable. This
allows regulators to appropriately train staff toreview advanced reactor license applications.
Accurate representations of technical readinessare also important so that regulators can performthe research needed to support a robust review of
the actual license application.

Adequate Regulatory Funding and Staff
for Advanced Reactor Licensing
Adequate funding is critical to having the rightpeople with the right skills at the right time toensure timely licensing of advanced reactors. In
the United States, the NRC, unlike most otherfederal agencies, is required to recover 90% of

140

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

its total budget through annual fees on current
licensees. These fees are variable and are in
addition to the fees the NRC directly charges
for its services (42 U.S.C. § 2214 (2005)),
making it difficult for the NRC to hire andtrain staff in anticipation of advanced reactor
license applications (even based on credible
pre-application interactions). Furthermore, theoperators of the current reactor fleet would haveto pay for these preparatory activities, which
do not benefit them and may not ultimately
be needed if the license applications neveractually materialize. Removing advanced reactor
licensing infrastructure (staff training, proceduredevelopment, etc.) from the fee base and allowing
for direct federal funding of these activities
would give the NRC the flexibility to prepare,as the agency deems appropriate, for advanced
reactor license applications. This approach is inline with the direct support and public funding
provided to other federal agencies that workwith rapidly developing technologies such as
pharmaceuticals (in the case of the U.S. Food andDrug Administration) and aviation (in the case of
the Federal Aviation Authority) (Finan 2016).

Finding:

Adequate funding for advanced reactor
licensing efforts is necessary to ensure
timely licensing actions. In the United States,
funding for such licensing development
efforts is currently limited and comes fromoperating nuclear facilities.

Recommendation:

The U.S. government should provide funding
for advanced reactor regulation outside the
NRC’s 90% fee recovery model to ensurethat sufficient resources are available whenneeded. At the same time, the nuclear
energy industry must communicate
regulatory function and research needs with
key U.S. entities, including the NRC, DOE,
and Congress, to ensure that adequate
funding is appropriated.

Sidebar 5.4: Does the NRC Need to Be Reorganized to Effectively Regulate Advanced Reactors?
A number of proposals have been put forward forreorganizing the U.S. Nuclear Regulatory Commission(NRC) so as to improve its efficiency and effectiveness.
One suggestion involves eliminating the NRC structureof appointed commissioners and moving to a single
administrator, similar to the structure of other regulatory
agencies, such as the U.S. Environmental Protection
Agency (EPA). This is not a new recommendation, it wassuggested as early as 1979 by the Kemeny Commission in
the aftermath of the Three Mile Island accident (UnitedStates President’s Commission 1979). The idea wasraised again in discussions with multiple experts as partof the research for this study, the argument being thatthe current collegial five-member commission involves
prolonged deliberations that may not be effective at
responding to the regulatory and technical demands ofassuring safety in advanced nuclear reactor designs. In
our view, however, changing from the current commission
structure to a single administrator would not be beneficial
and while it might appear to improve regulatory efficiency
in the short term, it could actually be counterproductivefrom an efficiency standpoint over the longer term.
Reorganizing the NRC under a single administrator
appointed by the president could subject the NRC togreater political pressure and distract its focus awayfrom the core mission of protecting public health andsafety. The current five commissioners are presidential
appointees, but the organization is arranged to minimize
political influence through the use of fixed five-year
terms during which commissioners cannot be removed
by presidential order. This structure has proved workablesince it was introduced under the original Atomic Energy
Act and as it was amended over the decades since,
and it has served to de-politicize both the selection ofcommissioners and the decisions they make.

Nuclear Regulatory Research (RES), which is responsible
for performing new research to support regulatory
activities. The New Reactor Office (NRO) was establishedafter 2000 in anticipation of advanced light water reactor(LWR) designs, but it is to be merged with NRR. NRR
and RES collaborate to develop the appropriate technicalbases and regulations for the current generation of LWRs.
This collaborative approach has been quite successful asevidenced by the development of general design criteria(NRC 2007c), risk-informed regulatory advances, and all
the supporting longer-range research that RES conducts
by way of providing technical assistance to NRR.
A similar organizational arrangement could be developed
for future regulatory initiatives related to advanced
nuclear reactors. For example, a new division of NRR
could be established to support advanced reactor
concepts while a parallel division could be established in
RES to support long-term research aimed at developing
the needed technical bases for safety criteria andguidance. Since NRO is now being reintegrated into NRR,
this division’s mission could be specifically focused on
regulating advanced reactor designs. A corresponding
group within RES would also be needed to support
longer-term research related to advanced reactors.
Finally, the NRC would need to organize experienced
senior managers and staff as well as new hires in NRR and
RES to focus on advanced reactor designs over the next
decade and to develop appropriate regulatory guidance
for these designs.

Another suggestion has been to reorganize the NRC staff
to provide a more efficient and effective organizational
structure for reviewing advanced reactor designs and fordeveloping the needed technical basis to conduct license
reviews. The NRC currently has three statutory offices:
Nuclear Materials Safety and Safeguards (NMSS), whichis responsible for radiological materials; Nuclear Reactor
Regulation (NRR), which is responsible for licensing andregulating commercial and non-commercial reactors; andChapter 5: Nuclear Reactor Safety Regulation and Licensing

141Effective Reviews and Efficient Resolutionof Staff Technical Questions
Reviewing license applications is a formal anditerative process. First, members of the regulatory
staff review applications and submit clarifying
questions or concerns as ‘Requests for Additional
Information’ (RAI). Applicants then prepare
responses or submit revisions to the license
application based on the RAIs. Regulatory staff
reviews the responses or updated application andrepeats this review cycle until staff believes theapplicable regulatory requirements have beensatisfied. While the formal nature of the process
guarantees public transparency, the processitself may require several iterations if RAIs or
applicant responses are unclear or incomplete.
These iterations can significantly extend the cost
and time associated with license review. Both theregulator and the applicant need to address thequestion of how to minimize the number of review
cycles and total time required to resolve technicalquestions related to the license application.
While a questioning attitude among regulatory
staff is essential to protect public health andsafety, staff and management need to clearlyand directly communicate technical concernsand questions to allow for more rapid resolutionof regulatory issues. Anecdotal evidence
suggests that NRC staff can sometimes become
focused on the precise resolution of technicalquestions without considering the larger safetysignificance of these questions. In other cases,
staff may be unwilling to make a formal decision
on a regulatory issue and may resort instead to
additional RAIs to gain further information. NRC
management may be hesitant to influence thestaff to make expeditious decisions for fear that
this will be misconstrued as direction to stop
pursuing a safety concern. This concern can beexacerbated if NRC staff is using engineering
judgment rather than historical precedent orexternal codes and standards to reach a decision
on a regulatory issue.

2

142

Effective resolution of technical questions from
regulatory staff is critical to control the durationand cost of license reviews. The licensing
processes for the Areva2 EPR and the Mitsubishi
advanced pressurized water reactor (APWR) were
substantially delayed by Areva’s and Mitsubishi’sslow resolution of technical questions raised
by NRC staff. NRC staff filed 629 formal RAIs
during the licensing process for the EPR and 1,111
RAIs during the licensing process for the APWR
(NRC 2015). These cases illustrate how delays
and cost overruns can arise as applicants attempt
to fully answer staff requests and follow up onquestions that may or may not actually impact
public health and safety.
While resolving technical questions is critical toensure the safe design and operation of advanced
reactors, it could be accomplished more rapidly.
NRC staff and management have recognized theneed to keep the RAI mechanism focused on key
safety issues and have begun scheduling more
frequent face-to-face meetings with applicants inrecent design certifications (e.g., for the APR1400
and NuScale licensing reviews). Such applicant–staff meetings have become a key way to clarify
design details and minimize needless RAIs
(NRC 2013). Both NRC staff and applicants haveacknowledged that that this approach improves
review effectiveness.

Nuclear Quality Assurance in the
United States
Nuclear quality assurance (NQA) is a cornerstoneof nuclear safety but the current implementationof NQA programs and requirements should be
reviewed to ensure that the additional time andcosts are justified and necessary to adequately
protect public health and safety.
Nuclear quality assurance aims to ensure thatthe structures, systems, and components(SSCs) required for safe operation of a nuclear
power plant will “perform satisfactorily inservice.” NRC requirements in 10 CFR Part 50,
Appendix B, and consensus implementation
guidance in the American Society of MechanicalAs noted in previous chapters, Areva’s reactor business was renamed Framatome and sold in 2018.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Engineers’ (ASME’s) Nuclear Quality Assurance
Requirements for Nuclear Facility Applications(NQA‑1) provide the basis for company-specificquality assurance programs for “designing,purchasing, fabricating, handling, shipping,storing, cleaning, erecting, installing, inspecting,testing, operating, maintaining, repairing,refueling, and modifying” nuclear safety-related
SSCs (NRC 2007h). NQA requirements andprocedures are intended to provide “reasonableassurance” that components can meet theperformance criteria assumed in plant safety
analyses. These requirements and procedures
can include additional documentation related
to procurement, additional physical inspections
or testing, or additional verification of design or
manufacturing activities.
The increased engineering and administrative
overhead associated with greater quality
oversight, coupled with additional manufacturingcosts for higher-quality operations, are largely
responsible for the increased costs associatedwith ‘nuclear-grade’ over ‘commercial-grade’ SSCs.
For certain components, the costs of a nucleargrade component may be substantially higher
than a similar commercial-grade component due
to additional environmental specifications andqualifications (e.g., operation in high temperatureor high radiation environments). These additional
specifications may accordingly result in substantial
modifications to the design or manufacturing of
the standard commercial-grade component.
The requirements and guidance in 10 CFR Part
50 Appendix B and NQA-1 for quality assurance,
as written, allow for the implementation offlexible and user-defined requirements to createa systematic process for ensuring quality,
accountability, and traceability of safety‑related
components. These written requirements do
not appear to present an undue burden, rather
anecdotal evidence suggests that deeper culturalissues may be responsible for many of thechallenges and costs associated with NQA.
Inconsistent, overly conservative, or verbatim
enforcement of subjective written quality
requirements can result in significantly higher

costs and longer production times for SSCs
without a commensurate increase in reliability or
quality. There are no published data comparing
the quality or reliability of SSCs designed or
produced under a nuclear quality assurance
program to those designed or produced undera standard or commercial quality assurance
program. It is currently unclear if NQA programs
have a quantifiable effect on SSC quality and there
was disagreement among interviewed quality
assurance engineers as to the effect of NQA
components on plant safety when comparedwith nominally identical, high-grade commercial
components (specific environmental qualifications
not withstanding).
The nuclear industry, consensus standards
committees, and regulators need to ensure thatthe implementation of NQA programs actually
increases plant safety and does not simply satisfy
procedural quality requirements for their own
sake. A better understanding is needed of thedifferences in terms of reliability, failure rates, andquality of SSCs produced under NQA programs
and standard quality assurance programs. Thisis critical in making more informed decisions
about the appropriate classification of SSCs andimplementation of NQA programs for safetyrelated applications.
NQA-related costs could be mitigated by reducing
the number of safety-related SSCs subject to
NQA programs. Inherent reactor safety design
features and other design choices can be used
to reduce the number of components thatmust be categorized as safety related. Use ofprobabilistic risk assessment to assess the safety
and risk significance of SSCs (e.g., risk-informed
categorization of SSCs as discussed in 10 CFR
50.69) can also be used to properly categorize
the quality requirements for low-risk SSCs.
Qualification of commercial-grade SSCs as
nuclear-grade SSCs through a commercial grade
dedication process may reduce NQA-related costs
for certain types of SSCs (e.g., pipes, conduit),
but is unlikely to reduce overall costs related to
NQA. High-quality verification standards required

Chapter 5: Nuclear Reactor Safety Regulation and Licensing

143

by commercial grade dedication processes still
have the same cost challenges as NQA design andmanufacturing processes.

Industry Licensing Challenges
The success of advanced reactor licensing
depends on both regulator and applicant. As thedesigners of such reactors continue to engage
in pre-application interactions with regulators,
they must ensure that they provide adequate
information and personnel support to enableeffective and efficient licensing.
Companies interested in designing and licensing
advanced reactor technologies must improve on
historic industry performance in four key areas:
regulator interactions, application quality, useof appropriate testing and analysis, and timely
resolution of regulatory questions. First, applicantsmust provide realistic responses to NRC queries
concerning expected licensing activities. This will
help the NRC hire and train the right staff in theright timeframe. Using license applications as amarketing activity to demonstrate commercial
viability limits the NRC’s ability to appropriately
prepare for advanced reactor reviews. Second,
applicants must submit complete, high-quality
license applications, not partially complete
applications, to meet timetables. High-quality
applications are critical to efficient review andapproval. Third, in cases where there is limited
operating experience with an advanced reactor
design, the applicant must perform adequate
experimental testing and associated validationof analysis methods to assure regulators of
the safety of the design. Finally, applicantsmust allocate sufficient technical resources
to respond to NRC RAIs in a timely manner.
Failure to meet agreed-upon schedules for
submitting RAI responses can challenge thescheduled availability of NRC staff resources andsignificantly impact the overall review timetable.
Without performance improvements in thesefour areas, licensing processes for advanced
reactors may be significantly more costly and takesignificantly longer.

144

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Pre-application Resolution of Policy Issues
Final resolution of policy issues before a license
application is submitted reduces the potential
for extended discussions and delays as decisions
are made on policy issues that could impact
reactor design. An example would be the issueof digital protection systems in the Areva EPR
design (Matthews 2013), which serves to highlightthe importance of early interactions between
applicants and regulatory staff and the need fortimely decisions on policy questions that are
critical to advanced reactor design. Some of thepolicy issues currently being considered by the
NRC are emergency planning, physical security
requirements, and allowable staffing of SMRs.

Safety and Operational Impacts of Revisions
to Models of Radiation Health Effects
Current operational limits on worker exposure
to radiation and emergency planning zone
requirements are based on the assumptionthat exposure to any level of ionizing radiation
constitutes a health hazard to humans with anincurred risk that is proportional to the dose
received—this assumption is also known as
the ‘linear no-threshold’ (LNT) hypothesis.
As reflected in regulatory standards, the LNT
hypothesis has significant implications for all
aspects of nuclear reactor design, operation,
maintenance, and emergency planning. Various
professional societies have addressed the need for
additional targeted research on the human healtheffects of low-dose ionizing radiation in light ofadvances in cellular biology (see Sidebar 5.5).

Sidebar 5.5: Rethinking the discussion on low-dose ionizing radiation
Current safety regulations for nuclear facilities are
based on a model of health effects from exposure toionizing radiation that assumes a linear relationshipbetween health effect and radiation dose. The model also
assumes that there is no ‘safe’ threshold for radiation
exposure—that is, a level of exposure below which
there are no health effects. Thus, the model is known
as the linear, no-threshold (LNT) model. That a linear
relationship exists between radiation exposure and healtheffects at high radiation doses is well established, largely
based on the Life Span Study of survivors of the atomic
bombings at Hiroshima and Nagasaki, Japan in 1945. The
extrapolation of the LNT relationship to low radiation
doses—that is doses below 100 millisievert (mSv) or
10 roentgen-equivalent-man (rem)—is, however, highly
debated (100 mSv is approximately 20% of the average
lifetime dose of radiation exposure in the United States,
including all natural and man-made sources).
At low doses below 100 mSv, correlating radiation
exposure with health effects is challenging due tothe presence the other factors (e.g., environmental,
genetic, etc.) that present known health risks of asimilar magnitude and that are not easily separable fromepidemiological data. Demonstrating a radiation-dose/
health-effect relationship with statistical certainty
from previous epidemiological data has thus provenimpossible. Studies of human cells have provided insights
to specific radiation damage and repair mechanisms. A
number of these studies have suggested that a non-linear
relationship exists between DNA damage due to radiation
exposure and cellular DNA repair mechanisms, but thiseffect appears to be highly dose rate dependent. Applying
these results to overall health effects is difficult, moreover,due to the complexity of interactions between human cells.
The LNT model is easy to understand, simple to use forradiation protection in practice, and may be considereda bounding hypothesis for radiation health effects. For
these reasons, it continues to be the radiation protection
model recommended by nearly all regulatory and advisoryorganizations, including the International Atomic Energy
Agency (IAEA), the International Commission on
Radiological Protection (ICRP), and the National Council
on Radiation Protection and Measurements (NCRP). It is
unclear, however, how accurate the LNT model may be at
the annual doses (approximately 1–10 mSv/year) normallyassociated with background radiation and commercial
applications of radiation protection. Use of the LNT modelfor health effects at low doses has had two major impacts
on the licensing and operation of commercial nuclear

power plants: it has led to the application of the ALARA(‘as low as reasonably achievable’) principle to worker
radiation protection, and it has affected offsite emergency
planning requirements for nuclear reactor plant sites.
In practice the ALARA principle means continuous efforts
to keep radiation exposures as low as achievable, often far
below the legally required radiation dose limits for nuclear
workers. It follows from the LNT model assumptionthat an incremental increase in radiation dose has anincremental adverse health effect. ALARA is implemented
as an iterative optimization process that seeks to balanceradiation dose risks and the costs of further reducing
radiation dose exposure. The result has been to impose
significant constraints on the scope and duration ofroutine operation and maintenance activities at nuclear
power plants. Utilities constantly strive to minimize
worker exposure to radiation in order to keep average andtotal worker doses as low as reasonably achievable. Whilethe use of ALARA has resulted in gradual but substantial
reductions in average worker doses at light water nuclear
power plants since the 1970s (from 9.7 mSv/year in 1973
to less than 1 mSv/year in 2015), the cumulative costs
associated with this approach have grown substantially.
The question is whether the costs associated with current
levels of radiation protection have been justified comparedwith other risks and whether the resulting reductions inworker doses have had any measurable health benefits.
Offsite emergency planning requirements for nuclear
power plants are based on the principle of minimizing
public harm following an accident or radiological releaseat a nuclear facility. The current response to such an event
is evacuation of the public away from areas around theplant that have been contaminated or from areas thatplant and governmental officials believe may becomecontaminated. While evacuation is an effective strategy
for reducing public dose, it carries significant risk of publicharm. Emergency evacuations have resulted in significant
numbers of injuries and premature deaths because they
involve rapidly transporting large numbers of people,
including moving and rehousing many sick and elderly
individuals, and force residents to re-locate for long
periods of times. The evacuation experiences following
the Fukushima nuclear accident have shown that current
emergency planning and evacuation requirements in all
likelihood do not correctly balance the risks of large-scaleevacuations with the health risks of low-dose radiation
exposure. An improved scientific understanding of
low-dose radiation health effects could inform better

Chapter 5: Nuclear Reactor Safety Regulation and Licensing145policy decisions with respect to emergency planningrequirements for nuclear power plants.
The high financial and social costs associated with current
radiation protection standards and practices can discourage
the use of nuclear technology as an energy resource, whichitself carries tangible social costs in terms of foregone
opportunities to provide cleaner air, lower carbon emissions,and greater access to energy for economic development.
Several ideas are worthy of urgent examination and further
research in the pursuit of a more effective and scientificallyrobust radiation protection standard. Specifically, we
recommend efforts to study the feasibility of:• Establishing an annual dose below which radiation
exposure is not regulated. This dose, likely on theorder of the background radiation, is not necessarily athreshold below which no health effects occur; rather
it is a dose below which health effects simply cannot
be identified in the presence of other health risks. This
concept is consistent with the policy statements of the
Health Physics Society and other international groups.
(Health Physics Society 2016) (Pradhan 2013)146• Expressing regulatory limits to radiation exposure forworkers and population groups in terms of ‘added
measurable radiological risk’ (i.e., the health riskincrement from radiation exposure), rather than interms of effective dose. This change would enable
a more transparent comparison of radiological risks
to risks incurred in everyday life and other industrial
activities. These limits would allow for a uniform
evaluation of both worker protection and emergency
planning requirements.
• Introducing individual dose limits by making useof advanced genomics techniques and assessing
individual parameters that influence the likelinessof radiation-induced damage to an individual(e.g., genetics, individual sensitivity, organ size,
metabolism, biokinetics, etc.). Advances in modelingand simulation, and in genomics and medical
science may, in the long term, make it possible toindividualize radiation protection requirements at thelevel of a specific worker. This would allow for thedetermination of individually-tailored dose and dose
rate constraints that correspond to a regulatory limit.

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Appendix A

GenX Input Values
This appendix provides all GenX input values used in Chapter 1.

Table A.1: United States investment costs
Technology
OCGT
CCGT
Coal
Nuclear (High)
Nuclear (Nominal)
Nuclear (Low)
Nuclear (Very Low)
Solar (High)
Solar (Nominal)
Solar (Low)Wind (High)Wind (Nominal)Wind (Low)
Battery (Nominal)
Battery (Low)
Battery (Very Low)
Coal IGCC+CCS
Gas CCGT+CCS (High)Gas CCGT+CCS (Low)
Hydro-Electric Storage
1

Overnight Cost[$/MW]$1,040,000$1,140,000$3,510,000$6,880,000$5,500,000$4,100,000$2,750,000$1,900,000$917,000$551,000$1,710,000$1,550,000$1,370,000$1,430,000$715,000$429,000$5,880,000$2,215,000$1,720,000
n/a 1

Construction
Period [years]
2
2
4
7
7
7
7
1
1
1
1
1
1
1
1
1
6
3
3
n/a 1

Life Time
[yr]
20
20
40
40
40
40
40
20
20
20
20
20
20
10
10
10
30
25
25
n/a 1

Interest
Rate
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
n/a 1

Future Cost
Investment Cost[$/MW][$/MW-yr]$1,122,192$114,334$1,235,708$125,899$4,116,254$345,345$9,110,864$764,383$7,288,691$611,506$5,433,388$455,850$3,644,345$305,753$1,972,723$200,989$952,782$97,073$573,062$58,386$1,781,823$181,539$1,614,758$164,518$1,422,690$144,950$1,486,496$221,574$743,248$110,787$445,949$66,472$7,468,797$663,698$2,491,724$233,506$1,934,883$181,323
n/a 1
n/a 1

Hydro-electric storage was considered to already be built, and so the investment cost is not considered.

GenX Input Values

149

Table A.2: China investment costs
Technology
OCGT
CCGT
Coal
Nuclear (Nominal)
Nuclear (Low)
Solar (High)
Solar (Nominal)
Solar (Low)Wind (High)Wind (Nominal)Wind (Low)
Battery (Nominal)
Battery (Low)
Battery (Very Low)
Coal IGCC+CCS
Gas CCGT+CCS (High)Gas CCGT+CCS (Low)
Hydro-Electric Storage
1

Overnight Cost[$/MW]$543,000$598,000$1,160,000$2,800,000$2,080,000$1,400,000$671,000$404,000$1,400,000$1,270,000$1,120,000$1,430,000$715,000$429,000$1,940,000$1,160,000$900,000
n/a 1

Construction
Period [years]
2
2
4
7
7
1
1
1
1
1
1
1
1
1
6
3
3
n/a 1

Life Time
[yr]
20
20
40
40
40
20
20
20
20
20
20
10
10
10
30
25
25
n/a 1

Interest
Rate
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
n/a 1

Future Cost
Investment Cost[$/MW][$/MW-yr]$587,012$59,807$646,392$65,857$1,358,804$114,000$3,705,368$310,873$2,762,183$231,742$1,444,300$147,151$697,565$71,071$419,559$42,746$1,453,702$148,109$1,317,401$134,222$1,160,703$118,257$1,486,496$221,574$743,248$110,787$445,949$66,472$2,465,502$219,091$1,303,406$122,145$1,012,126$94,849
n/a 1
n/a 1

Hydro-electric storage was considered to already be built, and so the investment cost is not considered.

Table A.3: United Kingdom investment costs
Technology
OCGT
CCGT
Coal
Nuclear (Nominal)
Nuclear (Low)
Solar (High)
Solar (Nominal)
Solar (Low)Wind (High)Wind (Nominal)Wind (Low)
Battery (Nominal)
Battery (Low)
Battery (Very Low)
Coal IGCC+CCS
Gas CCGT+CCS (High)Gas CCGT+CCS (Low)
Hydro-Electric Storage
1

150

Overnight Cost[$/MW]$865,000$953,000$3,510,000$8,140,000$6,070,000$1,660,000$804,000$483,000$2,360,000$2,140,000$1,890,000$1,430,000$715,000$429,000$5,875,883$1,846,802$1,434,086
n/a 1

Construction
Period [years]
2
2
4
7
7
1
1
1
1
1
1
1
1
1
6
3
3
n/a 1

Life Time
[yr]
20
20
40
40
40
20
20
20
20
20
20
10
10
10
30
25
25
n/a 1

Interest
Rate
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
n/a 1

Future Cost
Investment Cost[$/MW][$/MW-yr]$935,651$95,328$1,030,298$104,971$4,116,254$345,345$10,790,818$905,328$8,044,064$674,881$1,730,286$176,289$835,690$85,144$502,636$51,211$2,456,820$250,311$2,226,466$226,842$1,961,639$199,860$1,486,496$221,574$743,248$110,787$445,949$66,472$7,468,797$663,698$2,077,527$194,690$1,613,249$151,181
n/a 1
n/a 1

Hydro-electric storage was considered to already be built, and so the investment cost is not considered.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Table A.4: France investment costs
Technology
OCGT
CCGT
Coal
Nuclear (Nominal)
Nuclear (Low)
Solar (High)
Solar (Nominal)
Solar (Low)Wind (High)Wind (Nominal)Wind (Low)
Battery (Nominal)
Battery (Low)
Battery (Very Low)
Coal IGCC+CCS
Gas CCGT+CCS (High)Gas CCGT+CCS (Low)
Hydro-Electric Storage
1

Overnight Cost[$/MW]$890,000$980,000$3,510,000$6,800,000$5,070,000$1,660,000$800,000$481,000$1,890,000$1,710,000$1,510,000$1,430,000$715,000$429,000$5,880,000$1,900,000$1,470,000
n/a 1

Construction
Period [years]
2
2
4
7
7
1
1
1
1
1
1
1
1
1
6
3
3
n/a 1

Life Time
[yr]
20
20
40
40
40
20
20
20
20
20
20
10
10
10
30
25
25
n/a 1

Interest
Rate
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
8%
n/a 1

Future Cost
Investment Cost[$/MW][$/MW-yr]$962,159$98,029$1,059,487$107,945$4,116,254$345,345$9,007,755$755,732$6,714,872$563,364$1,722,902$175,536$832,124$84,780$500,491$50,992$1,966,651$200,370$1,782,256$181,584$1,570,266$159,985$1,486,496$221,574$743,248$110,787$445,949$66,472$7,468,797$663,698$2,136,386$200,206$1,658,955$155,465
n/a 1
n/a 1

Hydro-electric storage was considered to already be built, and so the investment cost is not considered.

Table A.5: United States operation cost
Resource

Unit Size(MWe)

Variable Heat Rate
Fixed
O&M Cost O&M Cost (MMBtu/($/MWe-yr) ($/MWhe) MWhe)

OCGT

200

$7,300$10.69CCGT

500$15,800

$3.37

IGCC
NuclearWind
Solar
Battery
IGCC
(CCS)

600
1000
1
1
1

$52,000$95,000$51,000$17,000$5,000

$7.34
$6.89
$0.00
$0.00
$0.00

600

$74,000

$8.58

500

$32,300$6.89(max total= 500)$4,600

$4.00

CCGT
(CCS)
HydroElectric
Storage

Fuel

NaturalGas
Natural
6.43
Gas
8.80 Coal
10.49 Uranium
n/a n/an/a n/an/a n/a
Coal
8.31
(CCS)
Natural7.49 Gas
(CCS)
9.75

n/a n/a

Minimum Ramping
Fuel Cost
Power Capability($/MMBtu)(%)(%)

CO2 Emissions(tons/MMBtu)

24%

100%

$7.52

0.053

38%

70%

$7.52

0.053

70%
50%
0%
0%
0%

30%
25%
100%
100%
100%

$3.14
$1.02
n/a
n/a
n/a

0.097
0.000
n/a
n/a
n/a

70%

10%

$3.14

0.010

30%

70%

$7.52

0.005

0%

100%

n/a

n/a

GenX Input Values151

Table A.6: China operation cost
Resource

Unit Size(MWe)

Variable Heat Rate
Fixed
O&M Cost O&M Cost (MMBtu/($/MWe-yr) ($/MWhe) MWhe)

OCGT

200

$5,102

$7.47

CCGT

500

$11,043

$2.36

IGCC
NuclearWind
Solar
Battery
IGCC
(CCS)

600
1000
1
1
1

$19,032$59,677$40,884$60,091$5,000

$2.69
$4.33
$$$-

600

$73,965

$8.58

500

$32,278$6.89(max total= 500)$4,600

$4.00

CCGT
(CCS)
HydroElectric
Storage

Fuel

NaturalGas
Natural
6.43
Gas
8.80 Coal
10.49 Uranium
n/a n/an/a n/an/a n/a
Coal
8.31
(CCS)
Natural7.49 Gas
(CCS)
9.75

n/a n/a

Minimum Ramping
Fuel Cost
Power Capability($/MMBtu)(%)(%)

CO2 Emissions(tons/MMBtu)

24%

100%

$12.92

0.053

38%

70%

$12.92

0.053

70%
50%
0%
0%
0%

30%
25%
100%
100%
100%

$3.78
$0.84
n/a
n/a
n/a

0.097
0.000
n/a
n/a
n/a

70%

10%

$3.78

0.010

30%

70%

$12.92

0.006

0%

100%

n/a

n/a

Minimum Ramping
Fuel Cost
Power Capability($/MMBtu)(%)(%)

CO2 Emissions(tons/MMBtu)

Table A.7: United Kingdom operation cost
Resource

Variable Heat Rate
Fixed
O&M Cost O&M Cost (MMBtu/($/MWe-yr) ($/MWhe) MWhe)

OCGT

200

$10,408$15.24CCGT

500$22,528

$4.80

IGCC
NuclearWind
Solar
Battery
IGCC
(CCS)

600
1000
1
1
1

$52,000$180,759$54,194$91,952$5,000$7.34$13.11$$$-

600$73,965

$8.58

500

$32,278$6.89(max total= 500)$4,600

$4.00

CCGT
(CCS)
HydroElectric
Storage

152

Unit Size
(MWe)

Fuel

NaturalGas
Natural
6.43
Gas
8.80 Coal
10.49 Uranium
n/a n/an/a n/an/a n/a
Coal
8.31
(CCS)
Natural7.49 Gas
(CCS)
9.75

n/a n/aTHE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

24%

100%

$15.39

0.053

38%

70%

$15.39

0.053

70%
50%
0%
0%
0%

30%
25%
100%
100%
100%

$3.14
$1.02
n/a
n/a
n/a

0.097
0.000
n/a
n/a
n/a

70%

10%

$3.14

0.010

30%

70%

$70.41

0.040

0%

100%

n/a

n/a

Table A.8: France operation cost
Resource

Unit Size(MWe)

Variable Heat Rate
Fixed
O&M Cost O&M Cost (MMBtu/($/MWe-yr) ($/MWhe) MWhe)

OCGT

200

$9,812$14.37CCGT

500$21,237

$4.53

IGCC
NuclearWind
Solar
Battery
IGCC
(CCS)

600
1000
1
1
1

$52,000$115,123$93,177$54,194$5,000

$7.34
$8.35
$$$-

600

$73,965

$8.58

500

$43,385$9.26(max total= 500)$43,385

$4.00

CCGT
(CCS)
HydroElectric
Storage

Fuel

NaturalGas
Natural
6.43
Gas
8.80 Coal
10.49 Uranium
n/a n/an/a n/an/a n/a
Coal
8.31
(CCS)
Natural7.49 Gas
(CCS)
9.75

n/a n/a

Minimum Ramping
Fuel Cost
Power Capability($/MMBtu)(%)(%)

CO2 Emissions(tons/MMBtu)

24%

100%

$15.39

0.053

38%

70%

$15.39

0.053

70%
50%
0%
0%
0%

30%
25%
100%
100%
100%

$3.14
$1.02
n/a
n/a
n/a

0.097
0.000
n/a
n/a
n/a

70%

10%

$3.14

0.010

30%

70%

$70.41

0.040

0%

100%

n/a

n/a

GenX Input Values

153

154

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix B

GenX Sensitivity Studies
To explore the sensitivity of our GenX modeling results (discussed in Chapter 1)
to different cost and technology assumptions, we performed a sensitivity study using
alternative parameters.
Cost assumptions for these sensitivity cases weretaken from a 2016 analysis by the U.S. National
Renewable Energy Laboratory (NREL) andincluded the following:• Low Renewables/Storage Cost
(60% of nominal NREL cost estimates)• High Renewables/Storage Cost
(200% of nominal NREL cost estimates)• High CCS Cost (130% of nominal cost)• High Natural Gas Cost (125% of nominal cost)• 99% Efficient CCS Systems (nominal efficiency
is 90%)• Demand Side Resources Considered 1• Extreme Weather Year (10% wind and solar
capacity for first week in July)2
The results of each region’s sensitivity study are
shown in Figures B.1 to B.6. We use the samedefinition of opportunity cost as in Table 1.7.

• Low Natural Gas Cost (75% of nominal cost)

(

)(

		
Average cost of electricity
Average cost of electricity
Opportunity Cost = generation without nuclear – generation with nuclear		technologies available
technologies available)‘Demand side resources’ refers to the grid operator’s ability to shift demand when the system is in danger of fallingshort of generation capacity, and to electricity consumers’ ability to curb demand when prices are too high. Our
scenarios assume that the grid operator can shift up to 5% of demand each hour, for a maximum period of six
hours. The amount that consumers will curb demand depends on how much they value electricity consumption,
also known as the price elasticity of demand for electricity (Sepulveda 2016).
2
We assume an extreme weather year to model the scenario for low renewable potential. Specifically, we reducewind and solar generation during the entire first week of July to 10% of its original value. The timing of thisreduction was chosen arbitrarily to illustrate the effect of prolonged cloudy and windless days.
1

GenX Sensitivity Studies

155

Nuclear Opportunity Cost ($/MWh)Figure B.1: Texas sensitivity study$120.00
Base Case$100.00

High Renewable/Storage Costs$80.00Extreme Weather Year$60.00High CCS Costs
99% Efficient CCS$40.00

Low Natural Gas Prices$20.00$-High Natural Gas Prices
Demand Side Resources
100

50

10

1

Low Renewable/Storage Costs

Emissions (g/kWh)

Nuclear Opportunity Cost ($/MWh)Figure B.2: New England sensitivity study$250.00
Base Case$200.00

High Renewable/Storage Costs
Extreme Weather Year$150.00

High CCS Costs$100.00

99% Efficient CCS
Low Natural Gas Prices$50.00$-High Natural Gas Prices
Demand Side Resources
100

50

10

1

Low Renewable/Storage Costs

Emissions (g/kWh)

Nuclear Opportunity Cost ($/MWh)Figure B.3: T-B-T sensitivity study$300.00
Base Case$250.00

High Renewable/Storage Costs$200.00

Extreme Weather Year$150.00

High CCS Costs
99% Efficient CCS$100.00

Low Natural Gas Prices$50.00$-High Natural Gas Prices
Demand Side Resources
100

50

10

Emissions (g/kWh)156

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

1

Low Renewable/Storage Costs

Nuclear Opportunity Cost ($/MWh)Figure B.4: Zhejiang sensitivity study$600.00
Base Case$500.00

High Renewable/Storage Costs$400.00

Extreme Weather Year

$300.00

High CCS Costs
99% Efficient CCS$200.00

Low Natural Gas Prices$100.00$-

High Natural Gas Prices
Demand Side Resources
100

50

10

1

Low Renewable/Storage Costs

Emissions (g/kWh)

Nuclear Opportunity Cost ($/MWh)Figure B.5: United Kingdom sensitivity study$300.00
Base Case$250.00

High Renewable/Storage Costs$200.00

Extreme Weather Year$150.00

High CCS Costs
99% Efficient CCS$100.00

Low Natural Gas Prices$50.00$-High Natural Gas Prices
Demand Side Resources
100

50

10

1

Low Renewable/Storage Costs

Emissions (g/kWh)

Nuclear Opportunity Cost ($/MWh)Figure B.6: France sensitivity study$200.00$180.00

Base Case$160.00

High Renewable/Storage Costs$140.00$120.00

Extreme Weather Year

$100.00

High CCS Costs$80.0099% Efficient CCS$60.00

Low Natural Gas Prices$40.00High Natural Gas Prices$20.00$-Demand Side Resources
100

50

10

1

Low Renewable/Storage Costs

Emissions (g/kWh)

GenX Sensitivity Studies

157

REFERENCES
National Renewable Energy Laboratory. 2016. Annual
Technology Baseline and Standard Scenarios. Accessed2017. https://www.nrel.gov/analysis/data-tech-baseline.
html.
Sepulveda, R. N. 2016. “Decarbonization of Power
Systems: Analyzing Different Technological Pathways.”
Thesis: Massachusetts Institite of Technology.

158

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix C

Verifying the GenX Results andBenchmarking GenX Results to JuiceBox
Results
To verify the GenX model, we analyzed a simple test scenario with nuclear and naturalgas generation. The GenX result for this simple scenario was compared to an analyticalsolution generated using a model that calculated every possible permutation and foundthe least-cost option. There is strong agreement between the analytical model results andthe GenX results.
In our simple scenario, natural gas and nuclear
are the only generation options available tosatisfy electricity demand in the region served
by ERCOT, the grid operator for the U.S. stateof Texas (ERCOT stands for Electric Reliability
Council of Texas). Our simple scenario further
assumes that nuclear plants have to operate at
100% of capacity, whereas natural gas generators
have unlimited ramping capabilities (that is, they
can adjust quickly to any level of power output
required by the system). The cost parametersassumed for each technology are shown in
Table C.1.

To determine the lowest total system cost, thescenario was run for every permutation of natural
gas installed capacity and nuclear installedcapacity, from 0 gigawatts (GW) to 100 GW.
It should be noted that peak demand on the
ERCOT system is 94.2 GW. System outcomes
were subject to two further criteria: (a) electricity
demand had to be met in full at all times and (b)allowable carbon emissions were subject to a hardconstraint (we tested for carbon limits of 1 gramcarbon dioxide per kilowatt hour (gCO2/kWh),
10 gCO2/kWh, 50 gCO2/kWh, 100 gCO2/kWh,and 500 gCO2/kWh). The results are shown in
Figures C.1 to C.5.

Table C.1: Cost parameters for the simple benchmarking scenario
NuclearNatural Gas

Investment Cost ($/MWh)611,500

125,900

Fixed O&M Cost ($/MWh)

95,00015,800

Variable O&M Cost ($/MWh)

6.89

3.37

Fuel Cost ($/MWh)

10.70

48.35

Verifying the GenX Results and Benchmarking GenX Results to JuiceBox Results

159

Figure C.1: Total cost array for carbon limitof 500g CO2/kWhFigure C.2: Total cost array for carbon limitof 100g CO2/kWhFigure C.3: T otal cost array for carbon limitof 50g CO2/kWhFigure C.4: Total cost array for carbon limitof 10g CO2/kWhFigure C.5: Total cost array for carbon limitof 1g CO2/kWh

160

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Optimal installed capacities of nuclear andnatural gas are shown in Figure C.6 for both theanalytical model and GenX. The figure shows that
there is very good agreement between the two
calculation methods.

This surprising result is an artifact of the input
assumptions, which force nuclear generators
to operate at 100% of capacity. As a result, themodel calculates excess electricity generation
during periods of low demand. This excess
generation is included when calculating average
electricity cost. In Figure C.8, which shows total
system cost, the highest cost occurs at the
1 gCO2/kWh emission limit, as one would expect.

We also compared the average cost of electricity
for each case (Figure C.7).
In Figure C.7, the average cost of electricity ishigher at a carbon limit of 50 gCO2/kWh than at
the more stringent limit of 1 gCO2/kWh.

100
90
80
70
60
50
40
30
20
10
0

Natural Gas

h

h
g/

g/

1

1
X

en

el

G

od
M

kW

kW

kW

10

g/

g/
X
en
G

M

od

el

10

g/
50

X

h

h
kW

h

h

kW

kW
g/
50

en

el
od
M

G

g/

0

kW
g/
G

en

X

10

10

0

kW

h

h
el
od
M

g/
0

kW

kW
g/

50

0
X

G

en

50
el
od
M

h

NuclearhTotal Installed Capacity (GW)

Figure C.6: Optimal installed capacities from GenX and analytical model results

Figure C.7: Optimized average cost of electricity

Average System Cost ($/MWh)120.00100.00
80.00
60.00

GenX

40.00

Model

20.00
0.00

500

100

50

10

1

Emissions (g/kWh)

Verifying the GenX Results and Benchmarking GenX Results to JuiceBox Results161

Figure C.8: O ptimized total cost of electricity

System Cost (Billion $)

80.00
70.00
60.00
50.00
40.00

GenX

30.00

Model

20.00
10.00
0.00

500

100

50

10

1

Emissions (g/kWh)Figure C.9: O ptimized total generation from nuclear and natural gas under different emissions constraints

Total Generation (TWh)8.00E+02
7.00E+02
6.00E+02
5.00E+02
4.00E+02
3.00E+02

Natural Gas

2.00E+02

Nuclear

1.00E+02

GenX Benchmarking
To benchmark the GenX model, we recreatedand simulated four of our GenX regionalmodeling cases using another electricity market
decisionmaking model: JuiceBox (Meier 2017).
The four scenarios are summarized in Table C.2.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

g/
1

kW

kW
g/

X
en

G

M

od

el

1

g/

h

h

h

h

kW

kW

10
X

en

G

M

od

el

10

g/

Finally, Figure C.9 compares the amount ofelectricity generated from nuclear and natural gas
under different carbon constraints. Here again,
there is strong agreement between the results
obtained using the analytical model and GenX.

162

g/

kW

kW

50
X

g/
50

en

el

G

od
M

h

h

h

g/

0

kW
g/

10

0

X
en

G

M

od

el

10

g/
0

kW

h

h

g/

50
X

0
50

en

el

G

od
M

kW

kW

h

0.00E+00

Table C.2: Benchmarking cases modeledusing JuiceBox
Case

Region

T10Y
T50Y
E10Y
E50Y

Tianjin, China
Tianjin, China
Texas, US
Texas, US

NuclearAllowed?
Yes
Yes
Yes
Yes

GenX Emissions
Target
10 g/kWh
50 g/kWh
10 g/kWh
50 g/kWh

Comparative Modeling Approaches
JuiceBox and GenX use different approaches tosimulate power plant operation. As backgroundfor this benchmarking exercise, it is helpful todifferentiate their underlying approaches. A recent
federal summary of electricity supply forecastingmodels distinguishes between two approaches:
electricity dispatch models and capacity expansion
or planning models (EPA 2017a). Key features ofeach type of model are summarized below—basedon these features, GenX can be considered anelectricity dispatch model, while JuiceBox fits thedescription of a capacity expansion or planningmodel.
• Electricity dispatch models are regularly usedby utilities and grid operators for short-termplanning. These models are designed toestimate the operation of generating units in
response to hourly, or sub-hourly, changes in
load; thus they account for transient constraints
on generator performance, such as start-up andramping limitations.
• Capacity expansion or planning models simplify
the treatment of short-term operational
constraints, making them more convenient
for long-term studies. Prominent examplesof this type of model include the Electricity
Market Module of the National Energy
Modeling System (NEMS) (U.S. Departmentof Energy 2017) and the Integrated Planning
Model (IPM), which has been used by the U.S.
Environmental Protection Agency (EPA) to
explore the impacts of environmental regulationon the U.S. power sector (EPA 2017b).
JuiceBox uses an industry-standard approach,termed load duration curve (LDC) modeling, toestimate the long-term performance of power
plants. LDC modeling involves several discrete
steps: (a) divide annual electricity demand intoa discrete number of time periods, (b) establish
a load duration curve by sorting demand fromhighest to lowest, (c) create loadshapes bymathematically characterizing the LDC (e.g.,
JuiceBox uses a polynomial spline to emulate theLDC), and (d) estimate each generating unit’s
contribution toward satisfying load based onleast-cost dispatch—that is, by adding generating
units to satisfy load in increasing order of marginal
operating cost and fuel cost.
To benchmark the GenX simulations using
JuiceBox, LDC loadshapes were created toemulate hourly electricity demand from GenX

simulations for each of the four cases in Table C.1.
A set of model generating units was constructed
and characterized for each case to closely reflect
the generation units simulated using GenX (interms of technology and fuel type, heat rate,
fixed and variable O&M costs, and capital cost).
LDC dispatch modeling was used to estimate
generating unit performance. Solar, wind, andenergy storage units were constrained to provide
the same annual output (in MWh) as estimatedin the GenX cases. Least-cost dispatch was used
to estimate the performance of the nuclear, coal,and natural gas units in satisfying residual load.
In contrast to the GenX simulations, which wereconstrained by an emissions target, JuiceBox
simulations included no emissions constraint.
To mimic the effect of an emissions constraint,
JuiceBox simulations applied a nominal carbon
fee of $40 per ton of CO2, so that power plants
with carbon capture and storage (CCS) werepreferentially dispatched ahead of non-CCS power
plants.
JuiceBox versus GenX results for annual
generation, CO2 emissions, and system cost are
discussed in the next section of this appendix.
JuiceBox uses a cost-of-service approach toestimate system costs. Production costs for eachpower plant unit are estimated on the basis ofcapital cost, variable and fixed operating andmaintenance (O&M) costs, and fuel cost. Fuelprice assumptions are the same as those usedin the GenX simulations. Cost of capital in the
JuiceBox simulations was based on documentation
for EPA’s Integrated Planning Model (EPA 2013),
which provides a technology-specific capitalcharge rate that takes into account discount rate,
book and debt life, taxes and insurance costs,
and depreciation schedule. The same U.S.-based
capital charges were used for both the U.S. andChina cases. JuiceBox emissions estimates area function of fuel consumption and unit-specificemission factors per unit of fuel consumed,
adjusted for the application of emissions controls.
Fuel consumption is calculated based on the
dispatch algorithm’s estimate of generation- andunit-specific seasonal heat rate. A summary ofJuiceBox input parameters is provided in Table C.3.

Verifying the GenX Results and Benchmarking GenX Results to JuiceBox Results163

Table C.3: Power plant parameters used in JuiceBox simulations
Generating
Unit Type

Available
in Cases

TX Gas
E10Y orPeaking
E50Y
TX Gas
E10Y orCombined
E50Y
Cycle
TX Nuclear E10Y or
LWR
E50Y
TX Coal
E10Y or
IGCC withE50Y
CCS
TX Gas CC
E10Y orwith CCS
E50Y
CHN Gas
T10Y orPeaking
T50Y
CHN Gas
T10Y orCombined
T50Y
Cycle
CHN Nuclear T10Y or
LWR
T50Y
CHN Coal
T10Y or
IGCC withT50Y
CCS
CHN Gas CC T10Y orwith CCS
T50Y
T50Y –
T50Y
Solar PV
T50Y –
T50Y
Wind
T50Y –
Battery
T50Y
Storage
T10Y –
T10Y
Solar PV
T10Y –
T10Y
Wind
T10Y –
Battery
T10Y
Storage
E50Y –
E50Y
Solar PV
E50Y –
E50Y
Wind
E50Y –
Battery
E50Y
Storage
E50Y –
E10Y
Solar PV
E50Y –E10Y
Wind
E50Y –
Battery
E10Y
Storage

164

Capital
Cost

CapitalCharge
Rate

10.69

1,038

10.63%

117.0

—

15.8

3.37

1,143

10.26%

117.0—

10,488

95.0

6.89

5,500

9.44%

0.0

—

3.14

8,307

74.0

8.58

5,876

9.68%

21.0

—

7.52

7,490

32.3

6.89

1,720

9.68%

10.6

—

12.92

9,750

5.1

7.47

543

10.63%

117.0

—

12.92

6,430

11.0

2.36

598

10.26%

117.0

—

0.84

10,488

59.7

4.33

2,796

9.44%

0.0

—

3.78

8,307

74.0

8.58

1,940

9.68%

21.0

—

12.92

7,490

32.3

6.89

900

9.68%

10.6

—

—

—

60.1

0

671

10.85%

0

22.2%

—

—

40.9

0

1,267

10.85%

0

17.4%

—

—

5.0

0

1,430

10.85%

0

5.3%

—

—

60.1

0

671

10.85%

0

18.2%

—

—

40.9

0

1,267

10.85%

0

17.4%

—

—

5.0

0

671

10.85%

0

3.3%

—

—

17.0

0

917

10.85%

0

23.3%

—

—

51.0

0

1,553

10.85%

0

35.7%

—

—

5.0

0

715

10.85%

0

7.1%

—

—

17.0

0

917

10.85%

0

22.9%

—

—

51.0

0

1,553

10.85%

0

35.6%

—

—

5.0

0

715

10.85%

0

6.7%

Fuel

Heat Rate

FOM

VOM

($/MMBtu)(Btu/kWH)(S/kW-yr)(S/MWh)

7.52

9,750

7.3

7.52

6,430

1.02

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD($/kW)CO2(LB/MMBtu)

Capacity
FactorForcingSummary and Comparison of Model Results
Table C.4 and Figure C.10 summarize the GenX
and JuiceBox results for each of the cases outlinedin Table C.3.1
Figure C.10 compares GenX and JuiceBox resultsfor electricity production by power plant fuelsource (generation mix). For each case, total
generation in the JuiceBox simulation is nearly
identical to the GenX result. This is expected,
given that JuiceBox loadshapes were derived fromGenX hourly demand data. Contributions fromsolar and wind resources (green bars), and battery
storage (yellow) were constrained in the JuiceBox
simulations to provide nearly identical output. The
remaining contributions from nuclear (purple),coal (black), and natural gas (blue) power plants
provide a visual benchmark for comparing GenX
and JuiceBox estimates of unit dispatch to satisfy
residual demand. The figure shows that the twomodels’ predictions for relative contribution by
fuel source are quite similar overall for each of thecases analyzed.

Differences between the GenX and JuiceBox
results reflect differences in their underlying
modeling approaches. In the T50 cases,
contributions from nuclear power are slightly
lower in the JuiceBox simulation (T50-JB). Thisdifference is attributable to power plant de-rating
factors in the JuiceBox model. As is typical inlong-term planning models, all generating units
are de-rated to reflect the likelihood of planned
and forced outages. In the T-50JB case, de-rating
diminishes the maximum possible contribution
from the nuclear units, thereby slightly increasing
reliance on gas and coal units. The same effects
of de-rating are visible when comparing results
for the T10 cases. In the E50 cases, JuiceBox
relies slightly more on natural gas units with CCS
than on combined cycle gas units (CCGT). This
result reflects slight differences between the
JuiceBox load shapes and GenX’s assumptions
for hourly demand. It may also reflect operational
constraints that are considered in the GenX model.
Specifically, gas with CCS may operate slightly lessin the E50Y GenX simulations due to ramping or
start-up constraints.

Table C.4: Summary and comparison of modeling results
Case

T50Y
GenX
JuiceBox
5.84
6.24

Cost (¢/kWh)Emissions(ton CO2/GWh)
CO2 Emission
Reduction
Relative to
Gas CC1 (%)

T10Y
GenX
JuiceBox
6.23
6.12

E50Y
GenX
JuiceBox
9.19
8.75

E10Y
GenX
JuiceBox
10.26
10.43

49.4

31.6

9.23

26.1

51.1

30.0

11.0

9.2

85.3

91.6

97.2

93.1

84.8

92.0

96.7

97.6

Figure C.10: Results for generation mix

Generation Mix (GWh) GenX and JuiceBox
Solar

Wind

NuclearCoal w CCS

Gas with CCS

CCGT

OCGT

Hydro Storage

Battery Storage

500,000
400,000
300,000
200,000
100,000
01

T50-GENX

T50-JB

T10Y-GENX T10Y-JB

E50Y-GENX E50Y-JB

E10-GENX

E10-JB

The CO2 emission rate for combined cycle natural gas generation is 398 g/kWh in the GenX simulations
and 342 g/kWh in the JuiceBox simulations.

Verifying the GenX Results and Benchmarking GenX Results to JuiceBox Results165

Estimated emissions are a function of thegeneration mix, specifically expected relianceon coal units relative to natural gas units. Bothmodels generate emissions estimates using
generation requirements, fuel efficiency (i.e.,heat rate), and fuel-specific emission rates. As
already noted, both GenX and JuiceBox produce
generally similar results for overall fuel mix in eachof the cases analyzed. Differences between theirresults for emissions correspond to differencesin predicted generation and, to a lesser extent,slight differences in the fuel-specific emission
rates assumed by each model. As one would
expect, both models show a reduction in average
emissions from the 50 gCO2/kWh scenario to
the 10 gCO2/kWh scenario. Though there aredifferences in the system-wide average emissions
rate predicted by the two models (in part, becauseof differences in the emission rates each model
assigns to different generation technologies,
particularly natural gas), it is more informative tolook at the level of overall system de-carbonizationachieved under different scenarios. Thus,
Table C.4 shows the average system emissions
as a percent reduction from the emissions eachmodel would estimate for combined cycle naturalgas generation,2 JuiceBox and GenX produce
similar estimates of overall decarbonization, withresults that differ by only 7% in the T50 case, 4%in the T10 case, 8% in the E50 case, and very little(0%) in the E10 case.

2

166

Cost results for different generation sources arealso relatively similar across all the modelingcases, with discrepancies ranging from as little as
2% (in the T10 and E10 cases) to as much as 15%
in the E50 case. Given that the JuiceBox model
was populated with cost assumptions from GenX,
these differences are a direct result of differencesin the two models’ predictions for fuel use(generation mix).
Figures C.11–C.14 show the estimated costof electricity generation in the year 2050 bygeneration source for each of the cases in Table
C.2. The figures show that GenX and Juicebox
produce cost estimates of comparable magnitude
for specific generation sources.

The CO2 emission rate for combined cycle natural gas generation is 398 g/kWh in the GenX simulations
and 342g/kWh in the JuiceBox simulations.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Figure C.11: Cost by generation source for T10Y

T10Y - Cost
35,000

Cost (in Billions of $)30,00025,00020,00015,00010,0005,000
0Natural Gas

Storage

Coal
JuiceBox Cost

NuclearRenewables

Total

GenX Cost

Figure C.12: Cost by generation source for T50Y

T50Y - Cost
30,000

Cost (in Billions of $)25,00020,00015,00010,0005,000
0Natural Gas

Storage

Coal
JuiceBox Cost

NuclearRenewables

Total

GenX Cost

Verifying the GenX Results and Benchmarking GenX Results to JuiceBox Results167

Figure C.13: Cost by generation source for E10Y

E10Y - Cost
60,000

Cost (in Billions of $)50,00040,00030,00020,00010,0000Natural Gas

Storage

Coal

NuclearJuiceBox Cost

Renewables

Total

GenX Cost

Figure C.14: C ost by generation source for E50Y

E50Y - Cost
50000
45000

Cost (in Billions of $)

40000
35000
30000
25000
20000
15000
10000
5000
0

Natural Gas

Storage

Coal

NuclearJuiceBox Cost

168

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Renewables

GenX Cost

Total

REFERENCES
Meier, P. 2017. “Power Sector Modeling Documentation
Version 2.6.” JuiceBox Clean Energy Strategy & Decision
Support. https://bit.ly/2OI4HwD.
U.S. Environmental Protection Agency. 2017a.
“Quantifying the Multiple Benefits of Energy Efficiency
and Renewable Energy: A Guide for State and Local
Governments.” July 3. Accessed February 5, 2018.
https://www.epa.gov/statelocalenergy/assessingmultiple-benefits-clean-energy-resource-states.
—. 2017b. “Clean Air Markets – Power Sector
Modeling.” January 10. Accessed February 5, 2018.
https://www.epa.gov/airmarkets/
clean-air-markets-power-sector-modeling.
—. 2013. Documentation for EPA Base Case v.5.13
Using the Integrated Planning Model. EPA450R13002,
Table 8-13.
U.S. Department of Energy. 2017. “Assumptions to theAnnual Energy Outlook 2017.”

Verifying the GenX Results and Benchmarking GenX Results to JuiceBox Results

169

170

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix D

One-Week Texas (ERCOT) GenX Analysis
This appendix provides a more detailed description of the GenX simulation results for asingle summer week (June 1 – June 7) of electricity generation in the Texas ERCOT region
for three technology scenarios (‘no nuclear,’ ‘nominal cost nuclear,’ and ‘low cost nuclear’)and four carbon dioxide (CO2) emission limits (100, 50, 10, and 1 grams per kilowatt hour
(gCO2/kWh)). Each figure represents hourly electricity production by specific generation
technologies. Note that negative generation values occur in periods when energy storage
is being charged. Normally these periods are followed by periods when the energy storage
system discharges power.
Figures D.1–D.4, show electrical power generation for June 1 – June 7 in ERCOT with no nuclear option
at different CO2 constraints.

100000
80000
60000
40000
20000
0
n

Ju

7-

n

CCS Technology

Ju

6-

n

Ju

Coal

5-

n

Ju

Natural Gas

4-

Storage

n

Ju

3-

n

Ju

Nuclear2-

un-20000J
1- -Electricity Generation(MW)

Figure D.1: ‘No nuclear’ technology case with an emissions limit of 100 gCO2/kWh in the ERCOT system:
The results show strong reliance on renewable generation. Natural gas is used to generate electricity
when renewable generation potential is low. Energy storage capacity is minimal.

Renewable

One-Week Texas (ERCOT) GenX Analysis

171100000
80000
60000
40000
20000
0
n

CCS Technology

Ju

7-

n

Ju

6-

n

Ju

Coal

5-

n

Ju

Natural Gas

4-

Storage

n

Ju

3-

n

Ju

Nuclear2-

un-20000J
1- -Electricity Generation(MW)

Figure D.2: ‘No nuclear’ technology case with an emissions limit of 50 gCO2/kWh in the ERCOT system:
The results show strong reliance on renewable generation. Natural gas powered combined cycle
turbines (CCGT) technology with carbon capture and storage (CCS) replaces natural gas generation
when renewable generation potential is low.

Renewablen

CCS Technology

Ju

7-

n

Ju

6-

n

Ju

Coal

5-

n

Ju

Natural Gas

4-

Storage

n

Ju

3-

n

Ju

Nuclear2-

un

100000
80000
60000
40000
20000
0
-20000-40000J
1- -Electricity Generation(MW)

Figure D.3: ‘No nuclear’ technology case with an emissions limit of 10 gCO2/kWh in the ERCOT system:
The results show strong reliance on renewable generation. No natural gas CCGT is used. Natural gas
fired generation with CCS and energy storage are used when renewable generation potential is low.

Renewable

100000
50000
0
n
Ju

7-

n
Ju

6-

n
Ju

5-

n
Ju

4-

n
Ju

3-

n
Ju

-100000
Nuclear172

2--50000nJu
1- -Electricity Generation(MW)

Figure D.4: ‘No nuclear’ technology case with an emissions limit of 1 gCO2/kWh in the ERCOT system: The results
show dominant reliance on renewable generation. Energy storage is heavily used (note the change inthe y-axis scale) when renewable generation potential is low.

StorageNatural Gas

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDCoal

CCS Technology

Renewable

Figures D.5–D.8 show GenX results for the June 1 – June 7 period in ERCOT with nuclear available
at nominal cost (i.e., $5,500/kWe overnight cost).

100000
80000
60000
40000
20000
0
n

CCS Technology

Ju

7-

n

Ju

6-

n

Ju

Coal

5-

n

Ju

Natural Gas

4-

Storage

n

Ju

3-

n

Ju

Nuclear2-

un-20000J
1- -Electricity Generation(MW)

Figure D.5: ‘Nominal cost nuclear’ technology case with an emissions limit of 100 gCO2/kWh in the ERCOT
system: The results show strong reliance on renewable generation. Natural gas powered CCGT
is used to generate electricity when renewable generation potential is low and there is minimal
reliance on electricity storage.

Renewable

100000
80000
60000
40000
20000
0
n

CCS Technology

Ju

7-

n

Ju

6-

n

Ju

Coal

5-

n

Ju

Natural Gas

4-

Storage

n

Ju

3-

n

Ju

Nuclear2-

un-20000J
1- -Electricity Generation(MW)

Figure D.6: ‘Nominal cost nuclear’ technology case with an emissions limit of 50 gCO2/kWh in the ERCOT system:
The results show strong reliance on renewable generation. Natural gas powered CCGT with CCS
replaces natural gas generation when renewable potential is low.

Renewable

n

Ju

7-

n

CCS Technology

Ju

6-

n

Ju

Coal

5-

n

Ju

Natural Gas

4-

Storage

n

Ju

3-

n

Ju

Nuclear2-

un

100000
80000
60000
40000
20000
0
-20000-40000J
1- -Electricity Generation(MW)

Figure D.7: ‘Nominal cost nuclear’ technology case with an emissions limit of 10 gCO2/kWh in the ERCOT
system: The results show strong reliance on renewable generation. Both CCS technology and nuclear
are used to generate electricity when renewable potential is low, with some contribution fromelectricity storage.

Renewable

One-Week Texas (ERCOT) GenX Analysis

173

n

CCS Technology

Ju

7-

n

Ju

6-

n

Ju

Coal

5-

n

Ju

Natural Gas

4-

Storage

n

Ju

3-

n

Ju

Nuclear2-

un

100000
80000
60000
40000
20000
0
-20000-40000J
1- -Electricity Generation(MW)

Figure D.8: ‘Nominal cost nuclear’ technology case with an emissions limit of 1 gCO2/kWh in the ERCOT system:
The results show strong reliance on nuclear and renewable generation.

Renewable

Figures D.9–D.12 show GenX results for the June 1 – June 7 period in ERCOT with nuclear available
at a low cost ($4,100/kWe overnight cost).

100000
80000
60000
40000
20000
0
n

CCS Technology

Ju

7-

n

Ju

6-

n

Ju

Coal

5-

n

Ju

Natural Gas

4-

Storage

n

Ju

3-

n

Ju

Nuclear2-

un-20000J
1- -Electricity Generation(MW)

Figure D.9: ‘Low cost nuclear’ technology scenario with an emissions limit of 100 gCO2/kWh in the ERCOT
system: Nuclear provides reliable baseload generation, while natural gas and renewables provide
peaking generation.

Renewable

100000
80000
60000
40000
20000
0
n
Ju

7-

CCS Technology

n
Ju

6-

n
Ju

Coal

5-

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDnJu

Natural Gas

4-

n
Ju

Storage

3-

174

n
Ju

Nuclear2--20000nJu
1- -Electricity Generation(MW)

Figure D.10: ‘Low cost nuclear’ technology scenario with an emissions limit of 50 gCO2/ kWh in the ERCOT
system: Nuclear provides reliable baseload generation, while natural gas and renewables provide
peaking generation.

Renewable

100000
80000
60000
40000
20000
0
n

Ju

CCS Technology

7-

n

Ju

6-

n

Coal

Ju

Natural Gas

5-

Storage

n

Ju

n

4-

Ju

3-

n

Ju

Nuclear2--20000nJuur
1H- -oElectricity Generation(MW)

Figure D.11: ‘Low cost nuclear’, with an emissions limit of 10 gCO2/ kWh in the ERCOT system: Nuclear provides
reliable baseload generation, while renewables and natural gas CCGT with CCS provide peaking
generation. Note that under this more stringent emissions limit, natural gas CCGT with CCS replaces
conventional natural gas in providing peaking generation.

Renewable

100000
80000
60000
40000
20000
0
n

Ju

7-

n

CCS Technology

Ju

6-

n

Ju

Coal

5-

n

Ju

Natural Gas

4-

Storage

n

Ju

3-

n

Ju

Nuclear2-

un-20000J
1- -Electricity Generation(MW)

Figure D.12: ‘Low cost nuclear’ technology scenario with an emissions limit of 1 gCO2/kWh in the ERCOT system:
Nuclear provides reliable baseload generation, while energy storage and renewables provide
peaking generation.

Renewable

One-Week Texas (ERCOT) GenX Analysis

175

176

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix E

The Nuclear Supply Chain
The nuclear supply chain can be divided into three major components (Figure E.1):
manufacturing, construction, and operation. Manufacturing includes the manufacturingof all necessary equipment for the reactor (e.g., reactor pressure vessel, steam generators,etc.) as well as the transport of manufactured equipment to the reactor site. Construction
includes the labor necessary to construct the reactor (e.g., welders, electricians, etc.).
It also includes the construction management needed to complete the project in a timely
manner and on budget. Operation includes the necessary labor and components needed
for continued operation of the reactor (e.g., certified operators, fuel enrichment, etc.).
Manufacturing Supply Chain
A modern light water reactor (LWR) has
about 2,000 kilometers (km) of cabling, 210
km of piping, 5,000 valves, 200 pumps, and
4,000 metric tons of forgings (World Nuclear
Association 2014). Major equipment includes thereactor pressure vessel, steam generators, pumps,
turbine-generator, condensers, and more. There
are 10 major consolidated nuclear reactor vendors:
Framatome (formerly known as AREVA), Candu
Energy, China National Nuclear Corporation,
China’s State Nuclear Power Technology
Corporation, GE & Hitachi, Korea Electric Power
Corporation, Mitsubishi Heavy Industries, Nuclear
Power Corporation of India, RosAtom, andToshiba/Westinghouse. Other significant nuclear
technology vendors include Babcock and Wilcox,
China General Nuclear Power Group, Doosan
Corporation, OMZ/Skoda, and Larsen & Toubro.

In addition, there are about 240 other suppliers of
nuclear-grade structures, systems, components,and services. In 2009, 147 companies werereported to hold an ‘N-Stamp,’ a nuclear
component certification, from the American
Society of Mechanical Engineers (ASME). Moreinformation on nuclear equipment suppliers canbe found in the World Nuclear Association’s
Supply Chain Reports (World Nuclear Association2014). Chapter 5 of this report delves deeper into
the subject of nuclear-grade equipment versus
commercial-grade equipment.
About a decade ago, there was concern about
potential bottlenecks in the supply chain forlarge forging capabilities, specialized alloys, andrare earth materials. However, the cancellationof planned plants and new investments in the
supply chain by existing suppliers have eased thisconcern. In addition, the transfer of manufacturing

Figure E.1: The nuclear supply chain

The Nuclear Supply Chain

177technology to China has resulted in an increase in
overall global capacity for manufacturing nuclear
equipment (especially forgings). In the event ofa rapid build-out of the nuclear industry, supply
bottlenecks should not be a concern as long as
care is taken to invest in the supply chain forcomponent and system manufacturing (World
Nuclear Association 2014).

Construction Supply Chain
Nuclear power plant projects are usually managed
by engineering, procurement, and construction(EPC) companies. The structure of thesecontracts varies from ‘multi-package’ contracts,
where the plant owner has direct control overthe construction of the plant and uses different
contractors for each work scope, to ‘single
package’ contracts where the EPC contractor is incharge of the entire construction project (World
Nuclear Association 2014).
There are a number of EPC companies withexperience in nuclear plant construction. Table
E.1 lists the EPC companies for four major reactor
designs (World Nuclear Association 2014).
While there are no logistical obstacles associatedwith the construction supply chain due to ashortage of EPC companies, the industry suffersfrom identified weaknesses in construction
management. Developing an experienced cadre ofconstruction managers is much more challenging.
This is an issue in all major technology andinfrastructure construction projects. With morethan 55 new nuclear reactors under construction
at 32 sites worldwide, efforts could focus onembedding junior construction managers at
many of these sites, thereby providing on-the-job
training. Having managers with real nuclear
construction experience leading this effort could
be an effective way to staff the next wave of
nuclear construction, starting in the late 2020s
and lasting until the late 2030s. Nevertheless,human resource development requires a deliberateand concerted effort by the nuclear industry.
Such an international collaborative effort needs
to start now. We would also note that increased
use of factory manufacturing could help reduce
construction supply chain challenges, in part bycentralizing the needed expertise.

Operation Supply Chain
There are no identified supply chain obstacles
in terms of current demand for personnel tooperate nuclear power plants. Currently, about
600 employees are required to operate eachreactor unit. At dual-unit sites, this number may
be reduced because the same personnel canTable E.1: EPC companies
Reactor Designer

EPC Companies

EPR (Framatome)• Électricité de France• Bechtel Corporation• Jacobs Engineering Group• China Nuclear Power Engineering Corporation• Shanghai Electric Group Corporation Ltd.
• Construtora Andrada Gutierrez SA• Construtora Quieroz Galvao

APR1400 (Korea Electric Power
Corporation)• Korea Hydro & Nuclear Power Corporation• Samsung C & T Corporation• Hyundai E & C• Daelim Industrial Corporation Ltd.
• Daewoo E & C• Doosan Babcock Ltd.
• SK E & C corporation Ltd.
• GS E & C Corporation

AP1000 (Westinghouse)• Chicago Bridge & Iron Corporation• Nuvia Ltd.
• China Nuclear Power Engineering Corporation

ABWR1350 (Toshiba Corporation and
Hitachi-GE)• Shaw Power Group Inc.
• Toshiba E & C Corporation Ltd.
• Toshiba Plant Systems & Services Corporation(World Nuclear Association 2014)

178

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDundertake common tasks. In addition, staffing
needs can vary depending on the size of thereactor. Figure E.2 reports two estimates of thenumber of plant employees (not including security
personnel) as a function of reactor size. In 2008,
the average figure for the United States was 0.58
employees per megawatt of electrical generating
capacity (MWe), with a range of 0.45–0.74
employees/MWe for single- to multiple-unit sites(Peltier 2010).

Figure E.3 shows the general break down of
employees across five categories: operators,
engineers, maintenance, security, and other(human resources, facilities, management,
support, etc.).
In the United States, it takes about two years totrain a plant operator. From the position of reactor
operator, it takes about one-to-five years to
become a control room operator. From the positionof control room operator, it takes about one-to-fiveFigure E.2: Number of plant employees (not including security) as a function of reactor size

Plant Staff (# per MWe)ORNL-8324

1.8
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
0

0

ORNL-10583

1000
2000
3000
4000
Total Plant Site Capacity (MWe)5000(ORNL/TM-8324 1982) (ORNL/TM-10583 1987)
Figure E.3: General breakdown of staffing needs for a nuclear power plant unit

Employees per Nuclear Unit
150

100

Operators
Engineers

100

Maintenance
Security

150

100

Other (HR, Facilities,
Management, Support, etc.)(McAndrew-Benevides 2016)

The Nuclear Supply Chain

179

years to become a reactor operator trainer(McAndrew-Benevides 2016). In total, it can takefour-to-twelve years to become a senior reactor
operator. These training times are outlined inTable E.2. The typical timeline indicates that there
would be enough time from when a new plant
construction project is announced to when theplant becomes operational to allow for the hiring
and training of necessary operators at all levels.
This conclusion is based on past U.S. experience
as well as current international experience. Insum, there is no bottleneck in the operations
supply chain.
Table E.2: Operator training times (United States)
Position

Years

Cumulative Years

Plant Operator

2

2Control Room Operator

1–5

3–7

Senior Reactor Operator

1–5

4–12

(McAndrew-Benevides 2016)

The other employees at a nuclear reactor that
require time to train are security personnel andengineers. The training schedule for security
personnel is shorter than a year (McAndrewBenevides 2016) and so there does not appear tobe any supply chain issue for this aspect of plant
operations.
Engineers nominally require four years ofeducation. However, there may be a deficit ofengineers with the experience as well as thetraining for plant operations. Figure E.4 shows
historical and current data on the number ofnuclear engineering graduates at the bachelor’s,
master’s, and Ph.D. level (Energy Futures Initiative,
Inc. 2017). While graduation numbers have sincerisen, the low number of graduates in the later
1990s and early 2000s led to a deficit of nuclear
engineers that would now be in their late 30s andearly 40s with 15–20 years of experience in theindustry. As a result, the workforce available toreplace retiring senior engineers may be young
and lacking in experience.

180

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Figure E.5 shows the price of uranium over time.
The figure shows that the price has declined
since it peaked in 2007. Because of falling prices,
investment in developing new uranium reserves
has also declined. As a result, total identified
uranium resources increased by only 0.1%
between 2013 and 2015. During that time, world
production of uranium also declined by 4.1%
(from 58,411 tons in 2013 to 55,975 tons in 2015)(Nuclear Energy Agency 2016).
Though there has been little growth in identified
uranium resources and uranium production overthe last two decades, the uranium supply chain
does not present an obstacle to the expansion of
the nuclear energy industry going forward. Thisis because there are enough identified resources
to handle an increase in demand. In 2011, MIT’s
Future of the Nuclear Fuel Cycle study (Kazimi, etal. 2011) found that currently existing as well as
committed, planned, and prospective uranium
production sites would be adequate to supply theInternational Atomic Energy Agency’s (IAEA’s)‘High Nuclear Growth’ scenario in which nuclear
generation grows from 377 gigawatts of electricalgenerating capacity (GWe), which requires
56,600 tons of uranium annually, to 683 GWe,
which requires 104,740 tons of uranium annually.
The concern is that current market conditions fornuclear fuel may discourage some planned andprospective investments in uranium production.
However, if demand for uranium were to increase,this would re-incentivize investment in production
facilities, averting supply shortages (Nuclear
Energy Agency 2016).
Current global uranium enrichment capacity
is approximately 58.6 million separative work
units (SWU), relative to current global demandof approximately 47.3 million SWU. Global
enrichment capacity in the year 2020 is projected
to be approximately 66.7 million SWU. Thus,
there is no expectation that the nuclear industry
will face near-term bottlenecks in the supply
chain for enriched uranium (World Nuclear
Association 2017).

Figure E.4: Numbers of nuclear engineering graduates in the United States(Energy Futures Initiative, Inc. 2017)
Figure E.5: Historical and current prices of uranium(Nuclear Energy Agency 2016)

The Nuclear Supply Chain

181

REFERENCES
Energy Futures Initiative, Inc. 2017. “The U.S. Nuclear
Energy Enterprise: A Key National Security Enabler.”
Kazimi, M., E. Moniz, C. Forsberg, S. Ansolabehere, J.
Deutch, M. Driscoll, M. Golay, A. Kadak, J. Parsons, and
M. Regalbuto. 2011. The Future of the Nuclear Fuel Cycle.
Massachusetts Institute of Technology, Cambridge,
Massachusetts: MIT.
McAndrew-Benevides, E., interview by K. Dawson. 2016.
Personal interview (October 26).
Myers, M. L., et al. 1987. “ORNL/TM-10583.”
Myers, M. L., et al. 1982. “ORNL/TM-8324.”
Nuclear Energy Agency. 2016. Uranium 2016: Resources,
Production and Demand. OECD.
Peltier, R. 2010. “Benchmarking Nuclear Plant Staffing.”
Power Magazine, April 1. https://www.powermag.com/
benchmarking-nuclear-plant-staffing/.
World Nuclear Association. 2017. “Uranium Enrichment.”
Accessed 2017. http://www.world-nuclear.org/
information-library/nuclear-fuel-cycle/conversionenrichment-and-fabrication/uranium-enrichment.aspx.
World Nuclear Association. 2014. The World Nuclear
Supply Chain Outlook 2030. London: World Nuclear
Association.

182

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix F

Process Heat Markets for Generation-IV
Nuclear Reactors
Nuclear power plants have been producing commercial electricity in the United States
for decades. In a traditional nuclear power plant, the reactor core produces heat, which istransferred to steam. The steam in turn generates electricity by a steam turbine. However,
the original product from the reactor core is heat. When utilized effectively this heat
may represent a product stream that has value independent of its potential for electricity
production. Chapters 1 and 3 of this report discuss the potential market for process heatfrom various Generation-IV reactors in the United States and the rest of the world. Thisappendix presents a more detailed discussion of the realistic size of this potential market
considering the fact that the major deployment hurdles for nuclear process heat atindustrial locations are a function of the required process temperature and the size of theindividual site.

PREVIOUS WORK
Previous efforts to analyze the potential useof Generation-IV reactors for process heatapplications have been primarily focused aroundthe U.S. Department of Energy’s Next Generation
Nuclear Plant (NGNP) project. Findings from threestudies that have examined the use of nuclear
process heat are detailed below.

Report Summary: Integration ofHigh-Temperature Gas-Cooled Reactors
into Industrial Process Applications
A 2010 report by researchers at the Idaho
National Laboratory, titled The Integration of HighTemperature Gas-Cooled Reactors into Industrial
Process Applications, offers a technical andeconomic evaluation of the potential for utilizing
high-temperature gas-cooled reactor (HTGR)
technology for process heat applications (Nelson,
et al. 2010). This report does not undertake adetailed market analysis, but rather assesses
the potential use of HTGR technology in specificapplications, including electricity generation,hydrogen production, methanol-to-synthetic

gasoline production, synthetic diesel production,ammonia production, oil sands production, andnatural gas production using coal as a feedstock.
Results from this analysis, showing the natural gas
price at which HTGR ‘breaks even,’ from a cost
perspective, as an alternative source of process
heat, are shown in Figure F.1.

Report Summary: High Temperature
Gas-Cooled Reactor Projected Markets andPreliminary Economics
A report titled High Temperature Gas-Cooled Reactor
Projected Markets and Preliminary Economics wascompleted in 2011 as part of the NGNP project(Idaho National Laboratory 2011). The authors
assessed co-generation facilities in the UnitedStates and also examined the potential to use
HTGR reactor technology for producing synthetic
fuels. The findings of this report are summarizedin Table F.1.

Process Heat Markets for Generation-IV Nuclear Reactors

183

Figure F.1: B reak-even natural gas prices calculated for four HTGR-integrated processes(Nelson, et al. 2010)
Table F.1: Results from 2011 report “High Temperature Gas-Cooled Reactor Projected Markets
and Preliminary Economics”
Power Requirement
(MWt)

Item
Co-generation andProcess Heat
Hydrogen Production
Oil Sands
Coal/Biomass to Fueland Feedstock
Electricity Generation
Total

Number of
600 MWt Modules

CO2 Emissions
Reductions(million metric tons)

Natural Gas Usage
Reductions(trillion cubic feet)

75,000

125

110

2.2

36,00018,000

60
30

15
23

0.44
0.41

249,000

415

80 to 410

N/A

110,400

184

488,400~150 replacing CCGT*
or~300 replacing coal plant
814
378 to 858

3.4 (if replacing
150 CCGT units)
6.45*Combined cycle gas turbine.

Report Summary: Survey of HTGR Process
Energy Applications
This report, which surveyed potential process heatapplications for HTGR technology, was producedby MPR Associates for the NGNP project (Konefal
and Rackiewicz 2008). The authors analyzed
12 industries and assigned priorities to theiravailability for nuclear process heat, including
petroleum refining, oil recovery, coal and natural
gas derivatives, petrochemicals, industrial gases,
fertilizers, metals, polymer products, cement,

184

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

pharmaceuticals, and paper and glass. The numberof reactors required to supply process heat foreach of these industries in the United States isshown in Figure F.2.
There are limitations to the existing literature inthis area. Previous reports did not assess the fullmarket for process heat on a site-by-site basis,
rather they undertook a market-wide analysis
and focused on only a subset of all industrialsites in the United States. Our analysis, byFigure F.2: Number of 500-MWth HTGR modules at 85% capacity required to meet process heat demands
for different industries(Konefal and Rackiewicz 2008)
Table F.2: Overall assumptions for process heat market analysis
Assumption

Justification

Two reactor sizes are available forprocess heat applications: 150 MWth or
300 MWth.

Based on soliciting expert advice on
Sites that are too small to accommodate
optimal reactor sizes for industrial process either of these reactor sizes are excluded
heat applications.
from the analysis. The flexibility ofconsidering two potential reactor
sizes, however, adds robustness to thecalculation.
Based on discussions with industry
There will be excess capacity at each site.
concerning the high levels of reliability
required for process heat supply. Natural
gas has been proposed as an alternative
back-up fuel, however the natural gas
supply may not be guaranteed.
See section “Heat and Electricity—
Co-Generation” below.

A minimum of two reactors are required
at each site.

Implication

Potential electricity generation capacity
will be coupled to the thermal load tomake use of excess heat capacity.
At least a 50°C temperature differential This level of differential is needed tois required for each potential application. give a high enough thermal driving force
between the outlet heat and the processtemperature.

contrast, attempts to catalogue and analyze eachindividual industrial site in the United Statesto assess its potential suitability for nuclear
process heat applications. This level of detail is
important since an individual site may not be large
enough to warrant a nuclear plant, even if theprocess heat the plant could provide would be of
sufficient quality.

High temperature applications are notconsidered in this analysis.

ASSUMPTIONS
Overarching assumptions for this analysis are
summarized in Table F.2.
Each Generation-III+ and Generation-IV reactor
concept has different available temperature limits,spanning a range from 60°C up to 900°C (withthe very high temperature reactor). The section“Heat Availability” below outlines the heat quality
available from each type of Generation-IV reactor.

Process Heat Markets for Generation-IV Nuclear Reactors

185

Heat and Electricity Co-Generation
While the energy required at most industrial sites
is in the form of process heat, these facilities also
require electricity. As a result many industrialsites also co-generate electricity. Co-generation
increases overall energy efficiency and reduces
fuel consumption relative to producing theheat and electricity separately. The U.S. Energy
Information Administration (EIA) collects anddisseminates information on all electricity
production facilities as part of its EIA-923 survey(U.S. Energy Information Administration 2017).
For this analysis we extracted information oncogeneration facilities (Table F.3), including
sites identified in the North American Industrial
Classification System (NAICS) as ‘industrial
cogen,’ ‘NAICS-22 cogen,’ and ‘commercial cogen.’Table F.3: Breakdown of U.S. fuel consumption
for cogeneration in 2015
Value

Percentage(%)
100.00Total Fuel Consumed (TWh)1,395Electricity Fuel Consumed (MMBtu)

659

47.23

Heat Fuel Consumed (MMBtu)

736

52.77

(U.S. Energy Information Administration 2017)

The ability of cogeneration facilities to produce
both electricity and heat provides an opportunity
to use excess nuclear heat to serve electricalload on site. For example, if an industrial siterequires 950 megawatts of thermal (heat)
energy (MWth), then installing four 300 MWthreactors will mean that 250 MWth is available forelectricity co-generation.

Differential Temperature Requirement
Generally, there are two forms of heat exchangers:
direct contact and indirect. Direct contact heatexchangers are systems where two streams are
mixed to facilitate heat transfer. In indirect heatexchangers, by contrast, there is a barrier between
the two process streams—for example, tubular
heat exchangers. Indirect heat exchangers aregoverned by the following equation:
Q = UADTtm

186

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Where Q is the heat exchanger duty, U is theoverall heat transfer coefficient, A is the surface
area of the heat exchanger, and DTtm is thelog mean temperature difference in the heatexchanger. This governing equation showsthat, holding duty and the overall heat transfer
coefficient constant, a reduction in the log mean
temperature difference means that the surface
area of the heat exchanger must be increased.
Therefore, to ensure that the driving force for theheat exchanger is adequate for the use of nuclear
process heat without requiring significantly larger
heat exchangers, we assume a minimum approachtemperature of 50°C for the heat exchanger.

Technology ReadinessWe examine the applicability of Generation-IV
reactors to provide process heat for industrial
processes that are already commercialized.
Our broad analysis focuses on the utilization of
nuclear process heat to produce synthetic fuels, a
potentially enormous industry.
Synthetic gas or ‘syngas’ is a fuel gas mixture
that can be used as a fuel and as a precursor
to chemicals like methanol, di-methyl ether,and hydrogen. Syngas is comprised primarily ofhydrogen, carbon monoxide, and limited amountsof carbon dioxide. Currently the major method
used to produce syngas is steam reforming of
natural gas. Water reacts with methane at hightemperatures, normally 800°C–900°C, overa metal catalyst, typically nickel (Reimert, etal. 2011):
CH4 + H2O

CO + 3H2

The water–gas shift reaction can also be used to
produce additional hydrogen by reacting carbon
monoxide with excess water concurrently withthe above reaction (Haussinger, Lohmuller, andWatson 2011):
CO + H2O

CO2 + H2

The potential to use nuclear-generated heat toproduce syngas is very limited, as the process
requires temperatures that are higher than the
maximum temperature achieved by various

Generation-IV reactor designs. While the very
high temperature reactor (VHTR) may produce
process temperatures that are sufficiently high, theengineering feasibility of this production pathway
is at low technical readiness. Currently, significant
research efforts are underway to produce syngas
at lower temperatures.

THE POTENTIAL MARKETFOR NUCLEAR PROCESS HEATIN THE UNITED STATESHeat Availability

Overall Energy Market in the United States

Nuclear process heat is available at different
temperatures depending on the reactor technology
used. Table F.4 gives outlet temperature andassumed maximum process heat temperature
available for different reactor designs. As anengineering limit, we assume a minimum
difference of 50°C between the process heattemperature required and the reactor outlet
temperature to provide a sufficiently large thermal
driving force for heat transfer.

In 2014, the United States consumed 98.3
quadrillion British thermal units (Btu) of primaryenergy (Figure F.3 and Table F.5). If this totalenergy demand were to be met by a fleet ofAP1000 reactors—at 1,117 MWe/3,400 MWth
(Schulz 2006) —then this would require a fleet
of approximately 1,040 reactors (Table F.5).
At present, of course, not all primary energy
demand could be met using nuclear reactors—
particularly in the transportation system (barring
the widespread deployment of electrified
motor vehicles). We examine the ability ofGeneration-III+ and Generation-IV reactors topenetrate additional markets for process heatapplications in the industrial sector.

Table F.4: Breakdown of U.S. fuel consumption
for cogeneration in 2015
ReactorOutletTemperature(°C)

Maximum
Process Heat
Temperature(°C)

Generation III+

300

250

Molten Salt Reactor

600

550

Very High Temperature
Reactor

900

850

High Temperature
Gas-cooled Reactor

700

650

Sodium Fast Reactor

500

450

Fluoride High Temperature
Reactor

600

550

Reactor TypeAs shown in Table F.4, the maximum reactor outlet
temperature is from the VHTR, which produces
helium gas at 900°C. Accordingly, our analysis
considers only those industrial processes that
require heat at temperatures below 850°C.

This section examines the potential for nuclear
process heat applications based on current
process heat requirements in the United States.

Site-Specific Greenhouse Gas Emissions
The U.S. Environmental Protection Agency (EPA)
collects greenhouse gas (GHG) emissions datafrom all industrial sites in the United States
above a minimum carbon-dioxide-equivalent(CO2-e) output of 25,000 metric tons (MT). The
GHG emissions are broken down into tons ofCO2-equivalent emissions from various sources,
including but not limited to direct CO2 emissions,methane emissions, and chlorofluorocarbon(CFC) and hydrofluorocarbon (HFC and HCFC)
emissions. The dataset is also broken down into
9 broad categories and 41 specific categories(Table F.6).

Process Heat Markets for Generation-IV Nuclear Reactors

187

Figure F.3: 2
 014 primary U.S. energy consumption by source and sector

Table F.5: 2014 U.S. primary energy consumption and equivalent number of AP1000 nuclear reactors
Industry
Transportation
Industrial
Residential& Commercial
Electric Power
Total

Primary Energy
Consumption(Quadrillion Btus)
27.0
21.4

Primary Energy
Consumption(TWhr)
7910
6270

Equivalent Numberof AP1000’sfor Thermal Load
286
227

11.3

3310

120

Percentage (%)
27.5
21.8
11.5

38.5

11280

408

39.2

98.3

28810

1040

100.0

Table F.6: Overview of sectors in EPA GHG dataset
Type of Site
Power Plant
Petroleum andNatural Gas Systems
Refineries
Chemicals
Minerals
Waste
MetalsPulp and Paper
Other
Total

188

Description
Electricity-producing facilities that include coal-fired
power stations and natural gas turbines.
Includes upstream oil and gas production facilities alongwith gas processing, compression, and pipeline facilities.
Refineries for processing crude oil into gasoline, kerosene
and other petroleum products.
Chemical facilities that include petrochemical and othercommodity chemical products like ammonia andhydrogen.
Includes cement, glass, lime, and soda ash production
facilities.
Includes landfills, solid waste combustion, and wastewater
treatment facilities.
Includes commodity metal production facilities such as
steelworks and aluminum refineries.
Facilities that produce wood pulp and paper.
Includes a broad range of different facilities, e.g., foodprocessing, ethanol production, and electronics
production.
Because multiple sites are included in multiple groups,
the sum of the parts is greater than the actual total.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

2015 GHG Emissions(Million MT CO2-e)

Total Number ofReporting Facilities

1,696

1,480

232

2,413

176

144

174

462

115

379

112

1,540

90

297

38

232

140

1,433

3,046

8,003

The EPA dataset was used to identify large
industrial sites that could potentially use nuclear
technology in process heat applications. Broadassumptions for this analysis are summarized inTable F.7. To calculate GHG reduction benefits,
the analysis also accounts for the different carbon
intensities of the fossil fuels being displaced(Table F.8).

Methodology
Direct interaction with the database was achieved
with a web-based application programming
interface (API) system, which was used todownload relevant data for manipulation with
Excel. Initially, the dataset was manipulated tocompare direct CO2 emissions from each site,
curtailed to consider only those facilities withannual CO2 emissions above 210,000 MT. The
logic for this cut-off point was that that thecleanest natural-gas-burning facilities, operating
at a 90% capacity factor, would produce

approximately 147 MW, just below the minimum
reactor size of 150 MW. This reduced the list of
facilities to 1,398 individual sites. These 1,398
individual sites were then segregated into different
sectors and industries based on their dominant
purpose and analyzed individually to determine
how much of their total fuel consumption could
be replaced by nuclear process heat. Factors
considered in the analysis included the required
process temperatures and the size of the heat loadthat could be served by nuclear process heat.

Power Plants
Because the specific purpose of this analysis is
to assess process heat applications for nuclear
technology, we do not consider facilities whose
primary business is to produce electricity (thoughobviously nuclear reactors can be used to generate
electricity and can thus replace power plants that
operate on other types of fuel).

Table F.7: Assumptions related to GHG emissions analysis
Assumption
The use of nuclear process heat affects
only direct CO2 emissions from heatproduction; it does not reduce processrelated emissions.
The processing facility has a capacity
factor of 90% (Sinnott, Richardson, andCoulson 2013).
Only non-biogenic emissions are
considered.
If the process produces a waste streamthat is used as a fuel then nuclear heat
will not replace this fuel source.

Justification
If GHGs are produced by chemical
reactions directly involved in the process,the use of nuclear technology to supply
process heat would not affect theseemissions.
No site runs consistently all year since
time is required for maintenance andunplanned stoppages.
Biofuels are considered to have no net
CO2 emissions on a full fuel-cycle basis
because these emissions are captured in
the regrowth of fuel feedstocks.
If a waste product can be used as a fuelsource then this is the most efficient useof the waste product.

Implication
None for results of this analysis.

The equivalent power rating for each site
will be higher than if averaged over theentire year.
Sites that have high carbon emissions,but the emissions come from biofuels,
e.g., sugar mills, are not considered.
Sites that have large waste productstreams will not require as muchadditional heat.

Table F.8: CO2 content by fuel source
Fuel

CO2 Content (MT/GWth)Coal (anthracite)
Coal (bituminous)
Coal (lignite)
Coal (sub-bituminous)
Diesel fuel and heating oil
Gasoline
Propane

353.9
318.4
333.4
331.7
249.7
243.3
215.2

Natural Gas

181.1(U.S. Energy Information Administration 2016)

Process Heat Markets for Generation-IV Nuclear Reactors

189

We do, however, consider co-generation facilities,
which produce both heat (usually in the form ofsteam) and electricity. Out of the 776 power plants
in EPA’s database that produce CO2 emissions
above the 210,000 MT limit, 115 are cogenerationsites. These sites were analyzed to determine
how many of them could be replaced with nuclear
facilities. The results are shown in Table F.9.
One of the largest steam production facilities in
the United States is the Midland Cogeneration
Venture (MCV), which supplies steam to Dow
and Dow Corning. MCV can produce steam up to
580°C so we use this temperature as the required
temperature limit for this analysis (Midland
Cogeneration Venture 2017).

Petroleum and Natural Gas Systems
The EPA database includes 131 sites that areclassified under petroleum and natural gas
systems. These sites are all involved in the
production or processing of oil and natural gas,e.g. onshore production facilities and natural
gas processing facilities. Due to the nature ofthese sites, we determined that none of them aresuitable for nuclear process heat applications.

RefineryThis section addresses nuclear process heatapplications in standalone refineries and refineries
coupled to petrochemical plants (chemical plantsthat are unrelated to refinery operations arecovered in a later section). The EPA database lists
108 refinery facilities that meet our emissions
threshold, of which 5 also have petrochemicalplants associated with the site.
Table F.10 describes the typical major units in an
oil refinery and their respective heat requirements.
All of these units, except for the alkylation unit,
operate at elevated temperatures—that is, above
350°C—with the fluidized catalytic converter
operating at temperatures up to 700°C. All are
therefore potentially suited to using process heatfrom a Generation-IV nuclear reactor.
Hydrogen is also commonly produced on site atrefineries using steam methane reforming. As
noted previously, hydrogen production by this190

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDmethod is not included in this analysis due to its
heat requirements. The highest potential processtemperature at a refinery is 700°C for the fluid
catalytic cracker, so we assume that nuclear
process heat must reach at least 750°C for use at
this type of facility.
Standalone Refineries
Out of the 108 sufficiently large refinery sites
in the EPA database, 103 of them do not have
petrochemical plants associated with them. The
purpose of these facilities is to process crude oil
into gasoline, kerosene, and other hydrocarbonbased products. Petroleum refining is a highly
complex and integrated process and each refineryis unique due to differences in desired output (e.g.,
aviation fuel versus diesel) and the crude feed
supply (e.g., light versus heavy crude). It should
be noted, however, that 47 of the refineries weanalyzed also produce hydrogen on site; emissions
from hydrogen production were not included inthis analysis. As each refinery has different heatrequirements, we examined each of the 103 sites
to determine how much nuclear process heat they
could utilize to replace fossil fuel consumption(Table F.11). Our results indicate a relatively
small potential for the uptake of nuclear process
heat in refineries, largely because of refineries’internal consumption of their own waste streams,
primarily fuel gas. Fuel gas is a waste productfrom the refining of crude oil and is burned onsite to provide process heat. For example, theCITGO Lemont Refinery in Illinois, with a refining
capacity of 167,000 barrels of oil a day, produces
only 5.36% of its emissions from fuel sources that
could be replaced by nuclear process heat.
Refineries with Petrochemical Plants
Five refineries in the United States are co-locatedwith petrochemical plants. These five facilities are
ExxonMobil Baytown, ExxonMobil Baton Rouge,
ExxonMobil Beaumont, Shell Deer Park, andNorco Manufacturing. All five facilities produce
olefin on site, using a process that requires large
amounts of heat to break down the alkane chains.
The two major olefins produced are ethylene
and propylene, which are primarily used in the
production of polyethylene and polypropylene,

Table F.9: Co-generation nuclear process heat potential
Category
Power Plants
Cogeneration
Power Plants
Cogeneration

Reactor Size

RequiredTemperature

Number of
Sites

Number ofReactors

Required Heat
Load

Supplied Heat
Load

150 MW

580°C

100

575

77,655 MW

86,250 MW

300 MW

580°C

70

276

70,983 MW

82,800 MW

Table F.10: Petroleum refinery major units with heat requirements
Processing Unit

Description

Heat Requirements

AtmosphericDistillation Unit

The atmospheric distillation unit is the major Before entering the column, the crude oilunit that performs the distillation of theis heated to approximately 350°C. The
crude oil. It separates naphtha, kerosene,temperature at the bottom of the column
diesel, and oil residue.
is also approximately 350°C.
Vacuum Distillation The vacuum distillation unit is used toRequires a reboiler temperature ofUnit
separate out the components of the oilapproximately 350°C.
residue without thermally cracking them.
Delayed Coker
The delayed coker is where the heaviest
The feed to the delayed coker has to behydrocarbons are raised above their thermal heated to approximately 480°C.
cracking point so that shorter hydrocarbons
and petroleum coke are formed.
Visbreaker
The visbreaker is a unit that also thermally
Feeds have to be heated to approximately
cracks heavy hydrocarbons into lighter
450°C.
hydrocarbons.
Hydrotreater
The hydrotreater is used to remove sulfur
The reactions that occur in thefrom the refined petroleum products.
hydrotreater occur between 300°C and
400°C (these are exothermic reactions
and thus not necessarily capture-able).
Hydrocracker
Cracks heavier hydrocarbons in theTemperature can be up to 425°C (thesepresence of hydrogen to produce saturated are exothermic reactions and thus nothydrocarbons.
necessarily captureable).
Fluid Catalytic
Cracks heavier hydrocarbons to produce
Operates at very high temperatures,
Cracker
shorter chained hydrocarbons.
approximately 700°C (needs to burn thecoke and thus is not recoverable).
Catalytic Reformer A process for converting low octane fuels
Requires heating up to approximately
into higher octane fuels by using a fixed bed 550°C.
catalytic reactor.
Alkylation
Converts low-value light hydrocarbons into Operates at approximately 30°C.
higher-value high-octane hydrocarbons.

Energy Usage(in 1,000 Btus
per barrel)
109.1

89.1
140.5

88.5
80.8

158.9
182.8
263.9
244.6

(U.S. Energy Information Administration 2016b) (Hydrocarbon Publishing Company 2012)
Table F.11: Nuclear process heat potential for standalone refineries
Category
Refineries –Stand Alone
Refineries –Stand Alone

Reactor Size

RequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

150 MW

750°C

20

80

9,972 MW

12,000 MW

300 MW

750°C

10

33

7,920 MW

9,900 MW

Process Heat Markets for Generation-IV Nuclear Reactors

191respectively. Olefins are produced by steam
cracking: decomposing ethane and propane insteam at high temperatures. The overall process isdifficult due to the kinetics of the reaction, as cokecan easily form in the reactor.
Steam cracking requires very high processing
temperatures (Figure F.4): both the ethaneand propane must be in the range of 880°C(Zimmermann and Walzl 2012). Due to the heattransfer constraints we applied in our analysis,
we determined that nuclear technology does
not produce process heat at sufficiently hightemperatures to support olefin production. Thus,
nuclear can supply process heat only for therefining process itself (Table F.12).

Chemicals
The EPA database includes a total of 124 chemical
facilities of sufficient size (based on their CO2
emissions) to justify examination for potential
nuclear process heat applications. These facilities
were divided into six subclasses for purposes ofthis analysis: fertilizers, hydrogen, petrochemicals,
nylon 66, phosphoric acid, and air separation.
Fertilizers
Twenty-one fertilizer production facilities in the
United States were considered in our analysis.
The most widely used fertilizers in the world areammonia-based compounds, which are used toenrich soil by adding nitrogen. Ammonia is also
a vital commodity because it is widely used as a

Figure F.4: P rocess gas temperatures along radiant coils(Zimmermann and Walzl 2012)
Table F.12: Nuclear process heat potential for refineries with petrochemical plants
Category
Refineries –Petrochemical
Refineries –SPetrochemical

192

Reactor Size

RequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

150 MW

750°C

5

35

4,962 MW

5,250 MW300 MW

750°C

5

19

4,962 MW5,700 MWTHE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDfeedstock chemical. Ammonia is produced by theHaber-Bosch process, which involves reacting
elemental hydrogen and nitrogen over an ironcatalyst at approximately 550°C:
N2 + 3H2

2NH3

Overall energy requirements for this process areintense due to the high pressure and chemical
potential required, coupled with hydrogenproduction and nitrogen separation. Ammonia
production facilities are usually co-located withurea and nitric acid production facilities, because
ammonia is a precursor for both products. Urea
is produced using the Bosch-Meiser process andnitric acid is produced using the Ostwald process;both processes are exothermic and do not occur attemperatures above 250°C.
Ammonia production involves two major
reactions: the production of hydrogen by steam
methane reforming and the synthesis of ammonia
from nitrogen and hydrogen (Table F.13). Table
F.13 shows that the first reaction, the productionof hydrogen, is energy intensive and endothermic,
while the second reaction is exothermic. As
already noted, our analysis concludes that basedon technical readiness today, hydrogen cannot be
produced using nuclear process heat. Since themajor heat requirements of ammonia production
are associated with hydrogen production, nuclear
process heat is also not suited for ammonia
production.
Table F.13: Ammonia production reactions
Reaction
CO2 + 4H2
CH4 + 2H2O
N2 + 3H2

2NH3

Enthalpy of Reaction
DH = 252.8 kJ/mol
DH = -91.8 kJ/mol

HydrogenThirty-four hydrogen production facilities in
the United States are sufficiently large to beconsidered for nuclear process heat applications.
However, as already noted, current methods forhydrogen production require process temperatureshigher than nuclear systems can provide. Thus,
nuclear process heat would not be useable atthese facilities with current technology.

Petrochemicals
Petrochemicals are the building blocks for modern
products like plastics and lubricants. We identified
48 different petrochemical facilities of sufficient
size to be considered in this analysis. These 48
plants were divided into seven sub-classes: olefins,carbon black, methanol, acrylonitrile, styrene,
glycol, and vinyl. Some facilities produce multiple
outputs: for example, some integrated chemicalplants make more than 50 products; in thosecases, the industrial facility was assigned to thesub-class that best fit its primary product.
Olefins
Olefins are a form of chained hydrocarbon
that contains at least one carbon double bond;common examples include ethylene, propylene,
and butadiene. Olefins are commonly used
to produce long-chain polymer products likepolyethylene and propylene. Our analysis includes
24 facilities in the United States that are primarily
used to produce olefins. As already noted,
however, the high temperatures required for the‘cracking’ process mean that nuclear process heatis generally not applicable to olefin production(though cracking could potentially be done at
900°C with either a VHTR or Joule heating).
Carbon Black
Carbon black is a sooty material comprised ofcarbon; it is commonly used as a filler in rubber
products, such as tires, and as a black pigmentin plastics and paints. There are nine sites in the
United States that primarily produce carbon black.
Production temperatures range from 1,200°C to
1,900°C and are therefore unsuitable for nuclear
process heat.
Methanol
Our analysis includes four facilities that havemethanol as their major product. Methanol is
primarily produced by passing syngas over acopper/zinc oxide (Cu-ZnO) catalyst at between
200°C and 300°C. Therefore, the limitingheat requirement is the production of syngas,
which was shown in a previous section to beincompatible with nuclear process heat. As such
nuclear process heat is not applicable to methanol
production facilities.

Process Heat Markets for Generation-IV Nuclear Reactors

193

Acrylonitrile
Our analysis includes three chemical plants
in the United States that primarily produce
acrylonitrile (C3H3N). The main use of acrylonitrile
is as a building block in the production ofpolyacrylonitrile, a common plastic. The main
reaction for producing acrylonitrile involves
ammoxidation of propylene in the presence of acatalyst, typically a molybdate-based catalyst.
This reaction takes place at 400°C–510°C andmay produce CO2 as a waste product.
2C3H6 + 2NH3 + 3O2

2C3H3N + 6H2O

The process temperature for styrene production
is potentially suitable for nuclear process heatapplications (Table F.15). None of the facilities waslarge enough to accommodate a 300 MW reactor.
Ethylene Glycol
Ethylene glycol (C2H6O2) is a useful chemicalthat is used in anti-freeze and as a building block
for polyester fibers. Our analysis includes fiveindustrial facilities that primarily produce glycol.
Ethylene glycol production involves reacting
ethylene oxide with water at 200°C using sulfuric
acid as a catalyst.

The required process temperature is suitable
for the use of nuclear process heat; hence weanalyzed the three U.S. acrylonitrile plants todetermine their nuclear heat requirements. We did
not include CO2 produced in the reaction in our
analysis. Only one of the sites had the potential touse nuclear process heat and only with a 150 MW
reactor (Table F.14).

C2H4O + H2OStyreneStyrene (C8H8) is an important commodity
chemical that is used in the production ofpolystyrene. Our analysis includes three industrial
facilities in the United States that primarily
produce styrene. The process involves thedehydrogenation of ethylbenzene, similar to theprocess used to make chained olefins, however atlower temperatures. The process reaction takes
place around 620°C over an iron oxide catalyst
with excess steam.

Nuclear process heat could be used for ethylene
glycol production (Table F.16). It should be
noted that ethylene glycol is produced in large
petrochemical plants that consume large
quantities of fuel gas.

C8H10

C8H8 + H2

C2H6O2The precursor ethylene oxide (C2H4H) is also
produced on site for immediate use. Ethyleneoxide is produced by the oxidation of ethylene
between 220°C and 275°C with a silver catalyst.
C2H4 + ½O2

C2H4O

Vinyl Chloride
Our analysis includes four vinyl chloride
production facilities. Vinyl chloride is mostcommonly used as a chemical building blockin the production of polyvinyl chloride (PVC).
The most common production pathway for vinyl
chloride consists of three steps: direct ethylene

Table F.14: Acrylonitrile nuclear process heat potential
Category
Chemicals –Acrylonitrile

Reactor Size
150 MW

RequiredTemperature

Number of Sites

510°C

Number ofReactors

1

RequiredHeat Load2

184 MW

Supplied
Heat Load
300 MW

Table F.15: Styrene nuclear process heat potential
Category
Chemicals –Styrene194

Reactor Size
150 MW

RequiredTemperature

Number of Sites

620°C

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

3

Number ofReactors

RequiredHeat Load
6696 MW

Supplied
Heat Load
900 MWchlorination, ethylene oxychlorination and finally
1,2-dichloroethane cracking to produce the vinyl
chloride.
The highest temperatures—between 500°C and
550°C—are required during the final cracking
stage. This temperature range is compatible withpotential nuclear process heat applications(Table F.17).

process temperature for nylon 66 is approximately
300°C. The potential CO2 reductions that could
be achieved using nuclear process heat at thesefacilities (i.e., not including emissions from thehydrogen reformer) are summarized in Table F.18.
Both facilities are large enough under specified
conditions to be potential candidates for nuclear
process heat applications (Table F.19).

Nylon 66

Phosphoric Acid

Our analysis includes two facilities that produce
nylon 66 and its precursors. Other than thehydrogen reformers at both sites, nuclear process
heat could be used to replace all other fuelconsumption at these facilities since the maximum

Our analysis includes two phosphoric acidproduction facilities in the United States. However,most GHG emissions from these facilities areprocess related and do not come from fossil fueluse to supply process heat. When only emissions

Table F.16: Ethylene glycol nuclear process heat potential
Category

Reactor Size

Chemicals –Ethylene Glycol
Chemicals –Ethylene Glycol

RequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

150 MW

275°C

5

17

2,090 MW2,550 MW300 MW

275°C

5

10

2,090 MW3,000 MW

Table F.17: Vinyl chloride nuclear process heat potential
Category

Reactor Size

Chemicals –Vinyl Chloride
Chemicals –Vinyl Chloride

RequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

150 MW

550°C

4

16

2,119 MW

2,400 MW300 MW

550°C

2

6

1,725 MW1,800 MW

Table F.18: Annual CO2 reduction potential using nuclear process heat applications at Nylon 66
production facilities
Total CO2 Emissions(tons)

Site
Ascend Performance
Materials
Invista S.a.r.l.

Hydrogen Reformer
Emissions (tons)

Nuclear–Displaceable Process
Heat Emissions (tons)

MWequivalent

1,061,220

186,991874,229

613

907,10370

907,033

635

Table F.19: Nylon nuclear process heat potential
Category
Chemicals –Nylon
Chemicals –Nylon

Reactor Size

RequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

150 MW

300°C

2

6

1,248 MW1,800 MW300 MW

300°C

2

10

1,248 MW1,500 MW

Process Heat Markets for Generation-IV Nuclear Reactors

195related to process heat are considered, neither of
the two facilities is large enough for a 150 MWthnuclear reactor.
Air Separation
Our analysis includes two facilities in the
United States that separate air. These facilities
produce oxygen and nitrogen by cooling air tocryogenic levels and then distilling its two major
components. The bulk of the associated CO2
emissions come from combined cycle natural gas
plants, which supply electricity—the major formof energy required at both sites. As a result, thesefacilities are not suitable for nuclear process heatapplications.

Minerals
Our analysis includes 149 facilities in the UnitedStates that are involved in minerals-based
production and are of sufficient size, based on
their CO2 emissions, to be potentially suitable fornuclear process heat applications. These facilities
can be further divided into five product categories:
cement production, lime production, glass
production, soda ash production, and titanium
dioxide production.
Cement Production
Cement is a key material in construction andbuilding that has been used for thousands of years.
The most common modern version of cement
is known as Portland cement. Portland Cement
is produced by milling and combining various
materials and then heating them in a cement
kiln. The kiln rotates while heating the materials
up to 1,500°C and producing clinker. After theclinker is cooled, it is milled and then mixed withlimestone and gypsum to produce the final cement
product. The mix of materials used may include
limestone, shells, chalk, marl, shale, clay, slate,blast furnace slag, silica sand, and iron ore. Dueto the high temperatures required to operate thekiln, nuclear process heat is not applicable tocement production.

196

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Lime Production
Lime, or calcium oxide, is a material used
extensively in construction; it can also be used asa chemical feedstock. Lime is typically producedby the decomposition of calcium carbonate (i.e.,
limestone) into calcium oxide and carbon dioxide:
CaCO3

CaO + CO2This calcining process requires temperatures
above 1,000°C; thus, nuclear process heat cannot
be used in lime production facilities.
Glass Production
Glass is produced by mixing and then melting
and annealing various oxides to form an
amorphous state. Common oxides used in glass
production include silicon dioxide, sodium oxide,
calcium oxide, magnesium oxide, and aluminum
dioxide. The required processing temperatures
are high: upwards of 1,500°C. For this reason,
nuclear process heat cannot be utilized forglass production.
Soda Ash Production
Soda ash, also known as sodium carbonate, iscommonly used in glass production (hence theterm ‘soda glass’) and other industrial processes.
While there are numerous ways to produce soda
ash, the United States has large deposits of trona,a double salt of sodium bicarbonate and sodium
carbonate, which can be processed into sodaash. Trona is calcined at approximately 300°C todecompose the sodium bicarbonate into sodium
carbonate and drive off any excess water:
2Na3H(CO3)2 • 2H2O

3Na2CO3 + 3H2O + CO2

Our analysis includes four facilities in the UnitedStates that produce soda ash (Table F.20).
All four of the facilities considered have sufficientheat requirements to be potentially suitable fornuclear process heat applications (note that
this would displace only the CO2 emissions
attributable to existing combustion sources, notprocess emissions) (Table F.21).

Titanium Dioxide Production

MetalsOur analysis includes five titanium dioxide
production facilities in the United States. Titanium
dioxide, also known as Titania, has a range of usesfrom titanium metal production to use as a white
pigment. Existing U.S. production facilities use achloride process to produce a high-purity Titania
product. The governing reactions are as follows:

There are 64 individual facilities in the UnitedStates that are involved in metal production
and that are large enough, based on their CO2
emissions, to be considered for nuclear process
heat applications. These metal production facilities
can be broken down into six distinct categories:
iron and steel production, aluminum production,
ferroalloy production, magnesium production,
alumina production, and manufacturing.

TiO2 + 2Cl2 + C
TiCl4 + O2

TiCl4 + CO2

Iron and Steel Production

2Cl2 + TiO2

The first reaction takes place between 800°C
and 1,200°C and the second reaction takes
place between 900°C and 1,400°C. Due to large
process-related CO2 emissions and very highprocess temperatures, these facilities are notsuitable for nuclear process heat applications.

Waste
There are 24 waste processing facilities in the
United States that are large enough, based on their
GHG emissions, to be considered in this analysis.
These facilities include landfills and solid waste
combustion plants. Because emissions from thesesources come from unavoidable waste streams,
nuclear process heat is not applicable to thiscategory of facilities.

Iron and steel are produced from iron ore, typically
hematite (Fe2O3) and magnetite (Fe3O4). The blast
furnace is the primary technology for producing
pig iron. Coke, flux, and sintered iron ore arecharged into the top of the blast furnace while hot
blast is injected through a tuyere at the bottom.
The hot blast reacts with the coke and otherinjected fuels to produce carbon monoxide, which
reduces the iron ore to pig iron. The escaping
gases however are not fully oxidized and can beused as a further fuel, known as blast furnace gas.
Before the iron-making process, the coking coalmust be transformed into coke. This is done byheating the coking coal in a coke oven in theabsence of oxygen. The coking process drives
off volatile gases from the coal and increases the
carbon concentration in the coke. These volatile

Table F.20: U.S. Soda ash production facilities
Annual CO2 Emissions
from Combustion Source(tons)
1,590,456.72

Annual CO2 Emissions
from Soda Ash Process(tons)
306,023.10

Tata Chemicals Partners

1,130,499.91

279,818.40

531

Solvay Chemicals

829,434.56

319,673.00

352

Ciner Wyoming

317,395.76

423,996.78

222

Facility
Tronox Westvaco

Power Equivalent for
CO2 Combustion Source
(MW)
697

Table F.21: Soda ash nuclear process heat potential
Category
Minerals –Soda Ash
Minerals –Soda Ash

Reactor Size

RequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

150 MW

300°C

4

14

1,802 MW2,100 MW300 MW

300°C

3

7

1,580 MW2,100 MW

Process Heat Markets for Generation-IV Nuclear Reactors

197

gases, known as coke oven gases, are combusted
to provide heat for both the coke ovens and therest of the steelworks.
Steel production presents opportunities to recoverheat and fuel from the process itself, in the form of
blast furnace gas and coke oven gas. The process
requires minimal amounts of fuel in addition to
the fuel that is directly produced from the process.
We focused on ArcelorMittal Steelworks at Burns
Harbor as a case study, since this facility produced
the highest CO2 emissions for a U.S. steelworks
plant in 2015.
In 2015, the ArcelorMittal steelworks at Burns
Harbor produced 9,460,478 MT of CO2. Of thistotal, 6,290,873.9 MT came from stationary
combustion sources and 3,169,604.1 MT camefrom the production process itself—that is, fromthe flares, coke pushing operations, and basic
oxygen process furnaces. The breakdown of CO2
emissions from stationary combustion sourcesat the ArcelorMittal facility in 2015 is shown in
Table F.22.
Table F.22: Breakdown of fuel types used and CO2
emissions at ArcelorMittal Steelworks
at Burns Harbor in 2015
Fuel Type
Blast Furnace Gas

MT of CO2
4,692,206

Percentage (%)
74.6

Coke Oven Gas

704,416

11.2

Natural Gas

894,25214.2

6,290,874

100.00

Total

Table F.22 shows that 14% of CO2 emissions fromthe Burns Harbor facility come from a non-process
related fuel source, i.e., natural gas. However,the facility requires higher process temperatures
than can be provided by nuclear process heat.
For example, the sintering plant is a critical stepto agglomerate iron ore fines into larger material.
This process requires temperatures upwardsof 1,200°C. Thus, nuclear process heat cannot
replace the process heat generated by natural gas
in current steel and iron making facilities.

Direct Reduced Iron (DRI)
An emerging technology uses syngas to directlyreduce iron ore. However, this method currently
accounts for only 6% (approximately) of global
iron production. Since nuclear process heat is
not suited for commercial syngas production atpresent, this type of facility was not considered forfurther analysis.
Aluminum Smelting
Aluminum smelting is used to reduce alumina into
aluminum metal. This process is accomplishedby using an electrochemical cell in what is known
as the ‘Hall-Heroult process.’ The alumina is
combined with molten cryolite (Na3AlF6) at
1,000°C, an electrical current is then run throughthis mixture, and the aluminum is reduced to metal
while the oxygen reacts with the carbon anode.
Al2O3 + 3⁄2 C

Because this process uses an electrochemicalcell, it requires vast amounts of electricity. The
two major sources of emissions from aluminum
facilities are the production of electricity andthe consumption of carbon anodes. Therefore,
aluminum smelting is not a candidate for nuclear
process heat applications.
Ferroalloy Production
We considered four facilities in the UnitedStates that produce ferroalloy, including silicon
metal production facilities and iron-silicon alloy
production facilities. All four facilities requiretemperatures much higher than can be provided
using nuclear process heat.
Magnesium Production
There is only one magnesium production facility in
the United States large enough to be consideredin this analysis: U.S. Magnesium. The production
process involves reducing magnesium chloride
in an electrolytic cell. Because it relies onelectrochemistry—in other words, electricity isused to produce the magnesium—this process is
not suitable for nuclear process heat.
MgCl2

198

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

2Al + 3⁄2 CO2

Mg + Cl2

Alumina Production

Pulp and Paper

Alumina is an oxide of aluminum that may
be used as a refractory, as an abrasive, and in
the production of aluminum metal. Alumina is
produced primarily from bauxite, an aluminumbased ore, using the so-called Bayer process. In
this process, the aluminum component of bauxite
is dissolved in sodium hydroxide, at approximately
180°C, and then cooled and recrystallized to
produce aluminum hydroxide:

There are 59 pulp and paper production facilities
in the United States that are sufficiently large,
based on their CO2 emissions, to be considered inthis analysis. It should be noted that we consider
emissions only from fossil-based sources andnot from the combustion of residual biomass(biogenic sources). For example, in 2015, thegeneral stationary fuel combustion units at theWestrock Virginia, Covington facility produced
1,036,795 MT of CO2, primarily from natural gas,along with 604,235.5 MT of biogenic CO2 fromthe combustion of wood and wood residues. Our
analysis considers only non-biogenic heat sources
as potential candidates for nuclear process heatapplications.

Al2O3 + 2NaOH

2NaAlO2 + H2O

2H2O + NaAlO2

Al(OH)3 + NaOH

This aluminum hydroxide is then calcined at hightemperatures, approximately 1,100°C, to produce apurified alumina product:
2Al(OH)3

Al2O3 + 3H2O

Due to the high temperatures required in the
calcining process, nuclear process heat is notapplicable to alumina production.
Manufacturing
There are three manufacturing facilities in the
United States that are large enough, based on their
GHG emissions, to be considered in this analysis.
These are foundries; facilities that melt steel andthen cast products. Due to the high temperatures
required to melt steel, nuclear process heat is notsuitable for these facilities.

Many different processes are involved in producing
pulp, from mechanical separation to chemical
processes. Once the pulp has been produced it
is compressed in a paper making machine where
the excess water is removed by compression
and heating. What all these processes have incommon, however, is that they require low processtemperatures, with a maximum temperature of
300°C required for the steam used to dry the
paper. Of the 59 sites we considered, 51 are large
enough to warrant the use of process heat from a
150-MW nuclear reactor (see Table F.23).

Other
An additional 38 facilities in the EPA dataset fallin the category of ‘other.’ Of these, we analyzed
28 facilities, divided into six categories: foodprocessing, cellulose acetate, specialty plastics
and chemicals, universities, brine, and gold mining.

Table F.23: Pulp and paper nuclear process heat potential
Category

Reactor Size

RequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

Pulp and Paper

150 MW

300°C

51

142

16,890 MW

21,300 MW

Pulp and Paper

300 MW

300°C

22

42

10,742 MW

14,700 MW

Process Heat Markets for Generation-IV Nuclear Reactors

199

Food Processing
Our analysis includes 18 food processing facilities
across the United States, producing a range of
products from vitamin E to bioethanol and sugar,
to corn starch and fructose syrup. Given thisbroad variety of products, we make assumptions
about maximum operating temperatures atthese facilities. Specifically, we assume that the
maximum operating temperature for processes
that use complex organics and food-basedmaterials is approximately 300°C (for example,
given that sucrose decomposes at 186°C, higher
temperatures can be assumed to cause theorganic compounds in these products to begin
decomposing). This assumption leads to theresults summarized in Table F.24.
Cellulose Acetate
The cellulose acetate production plant in Narrows,
Virginia, is the only U.S. facility of this type large
enough to warrant consideration for nuclear

process heat applications. Cellulose acetate is theacetate ester of cellulose; it has a wide range ofuses, from film base to synthetic fiber. Cellulose
acetate is produced by the reaction of acetic
acid and acetic anhydride with cellulose material
in the presence of a catalyst, typically sulfuric
acid. The reaction has a long residence time
during which the cellulose acetate precipitatesout of solution and afterwards is filtered out andspun. The process temperatures involved are notexcessively high, approximately 200°C. As such,
nuclear process heat could be used at this facility(Table F.25).
Specialty Plastics and Chemicals
Our analysis includes five facilities that produce
specialty chemicals and plastics (Table F.26). The
maximum process heat requirement for thesefacilities is 550°C, for the production of catalysts.
Results for these five facilities, including required
heat loads, are summarized in Table F.27.

Table F.24: Food processing nuclear process heat potential
Category

Reactor Size

RequiredTemperature

Number ofReactors

Number of Sites

RequiredHeat LoadSupplied
Heat Load

Other – Food

150 MW

300°C

14

78

10,345 MW

11,700 MW

Other – Food

300 MW

300°C

10

38

9,549 MW

11,400 MW

Table F.25: Other – Cellulose acetate nuclear process heat potential
Category

Reactor Size

Other – Cellulose
AcetateOther – Cellulose
AcetateRequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

150 MW

200°C

1

3

350 MW

450 MW

300 MW

200°C

1

2

350 MW

600 MW

Table F.26: Required temperatures at specialty plastics and chemicals production facilities
Site

200

Required Temperature

Justification

SABIC Innovative Plastics,
Mt. Vernon
Ticona Polymers
Incorporated

Thermoplastics

Product

300°C

Acetyl and liquid crystal
polymers and thermoplastics

300°C

Oxea Corp Bay City Plant

Intermediate alcohols,
aldehydes and esters

250°C

Kraton Polymers US

Synthetic polymers and rubbers

300°C

BASF Corporation

Catalysts

550°C

Above this temperaturethermoplastics start to degrade
Above this temperaturepolymers and plastics start
to degrade
Process temperature for thehydroformylation of olefins
to produce aldehydes
Above this temperaturepolymers start to degrade
Production of zeolite catalysts
require the conversion of
kaolin to metakaolin at thistemperature

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Universities
Seven universities are included in this analysis inthe ‘other’ category. These are all large facilities
that produce their own heat and cooling wateron site with no industrial purpose for theirheat generation. We assume that the required
temperature for internal heat loads at these
universities is 200°C. Due to their smaller size,
none of these facilities is large enough for a 300
MWth reactor. The total potential for nuclear heatis shown in Table F.28.
Brine
Searles Valley Minerals is an industrial facility
located in California that produces borax, boric
acid, sodium carbonate, and other products using
the brine from Searles Lake. Ninety-five percentof the facility’s direct CO2 emissions are fromtwo pulverized coal boilers; the remaining 5%
is attributed to natural gas consumption. These
three energy sources produced approximately
4853.91 gigawatt hours (GWh) of heat in 2015,
representing an effective heat load of 616 MW.
Most of this thermal energy was used to evaporate
water from the brine solution in order to produce
anhydrous products; given the low processtemperature required, nuclear process heat is

potentially applicable. Subject to our assumptions,Searles Valley Minerals would have the potential
to operate three 300-MW reactors (Table F.29).
Gold Mining
One gold mine is included in the ‘other’ category.
This facility is vertically integrated in that it
both mines and processes gold. Due to the hightemperatures required to smelt gold, which has amelting point of 1,064°C, nuclear process heat is
not applicable to this facility.

THE OVERALL MARKET FOR
INDUSTRIAL PROCESS HEATIN THE UNITED STATESOur estimate of the overall potential for nuclear
process heat applications in the United States
is summarized in Tables F.30 and F.31, whichassume reactor sizes of 150 MWth and 300
MWth, respectively. The total heat load in our
analysis is 131,231 MW, or 1,035 terawatt hours(TWh) per year. This represents only 16.5% of
the total primary heat used in the U.S. industrial
sector. There are two major reasons for thisrelatively small market potential. The first is thatsome major industrial consumers of heat energy,
primarily refineries, use fuel gas produced during

Table F.27: Specialty thermoplastics nuclear process heat potential
Category
Other – Specialty
Chemicals
Other – Specialty
Chemicals

Reactor Size

RequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

150 MW

550°C

4

9

994 MW

1,350 MW300 MW

550°C

1

2

349 MW

600 MW

Table F.28: Universities nuclear process heat potential
Category
Other –
Universities

Reactor Size
150 MW

RequiredTemperature
200°C

Number of Sites

Number ofReactors

6

RequiredHeat Load
12

1,308 MW

Supplied
Heat Load
1,800 MW

Table F.29: Brine nuclear process heat potential
Category

Reactor Size

RequiredTemperature

Number of Sites

Number ofReactors

RequiredHeat LoadSupplied
Heat Load

Other – Brine

150 MW

300°C

1

5

616 MW

750 MW

Other – Brine

300 MW

300°C

1

2

616 MW

900 MW

Process Heat Markets for Generation-IV Nuclear Reactors

201the refining process to meet a large share of
their own energy needs. A second reason is theinability to commercially produce hydrogen undercurrent constraints. If hydrogen could be produced

on a commercial scale at nuclear process heattemperatures, the potential size of the market
would expand rapidly. The current installedcapacity of Generation-II reactors in the United

Table F.30: Nuclear process heat potential – 150-MWth reactor size
Category
Power Plants –Cogeneration
Refineries –Stand Alone
Refineries –Petrochemical
Chemicals –Acrylonitrile
Chemicals – Styrene
Chemicals –Ethylene Glycol
Chemicals –Vinyl Chloride
Chemicals – Nylon
Minerals –Soda Ash
Pulp and Paper
Other – Food
Other -Cellulose
AcetateOther –
Specialty Chemicals
Other – Universities
Other – Brine

RequiredTemperature

Number of Sites

Number of Reactors

RequiredHeat LoadSupplied
Heat Load

580°C

100

575

77,655 MW

86,250 MW

750°C

20

80

9,972 MW

12,000 MW

750°C

4

35

4,962 MW

5,250 MW

510°C

1

2

184 MW

300 MW

620°C

3

6

696 MW

900 MW

275°C

5

17

2,090 MW2,550 MW

550°C

4

16

2,119 MW

2,400 MW

300°C

2

6

1,248 MW1,800 MW

300°C

4

14

1,802 MW2,100 MW

300°C

51

142

16,890 MW

21,300 MW

300°C

14

78

10,345 MW

11,700 MW

200°C

1

3

350 MW

450 MW

550°C

4

9

994 MW

1,350 MW

200°C

6

12

1,308 MW1,800 MW

300°C

1

5

616 MW

750 MW

Table F.31: Nuclear process heat potential – 300-MWth reactor size
Category
Power Plants –Cogeneration
Refineries –Stand Alone
Refineries –Petrochemical
Chemicals –Ethylene Glycol
Chemicals –Vinyl Chloride
Chemicals – Nylon
Minerals –Soda Ash
Pulp and Paper
Other – Food
Other –
Cellulose Acetate
Other –
Specialty Chemicals
Other – Brine

202

RequiredTemperature

Number of Sites

Number of Reactors

RequiredHeat LoadSupplied
Heat Load

580°C

70

276

70,983 MW

82,800 MW

750°C

10

33

7,920 MW

9,900 MW

750°C

4

19

4,962 MW5,700 MW

275°C

5

10

2,090 MW3,000 MW

550°C

2

6

1,725 MW1,800 MW

300°C

2

10

1,248 MW1,500 MW

300°C

3

7

1,580 MW2,100 MW

300°C

22

42

10,742 MW

14,700 MW

300°C

10

38

9,549 MW

11,400 MW

200°C

1

2

350 MW

600 MW

550°C

1

2

349 MW

600 MW

300°C

1

2

616 MW

900 MWTHE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

States is approximately 300 GWth, meaning that
our estimate of overall potential for heat load
applications comes to approximately two-fifths
the capacity of the existing fleet.

MARKETS FOR NUCLEAR PROCESSHEAT OUTSIDE THE UNITED STATESThe detailed information used to generate theresults shown in Tables F.30 and F.31 is notavailable for industrial facilities in the rest of theworld. To produce a rough estimate of the size ofthe global market for industrial process heat, we
scaled the U.S. data using two factors: U.S. refining
capacity relative to worldwide refining capacityand U.S. gross domestic product (GDP)—ameasure of overall economic output—relative toworld GDP. Our major assumption in applying
these scaling factors is that the global distributionof plant capacities is the same as in the UnitedStates. In general, however, the United States has
a higher proportion of large-capacity plants. Thismeans that our estimate likely over-predicts thepotential for nuclear process heat applications at
industrial facilities worldwide.

SCALING FACTORSThis section describes the methodology used togenerate factors for scaling U.S. results to the restof the world, based on refinery capacity and GDP.

Refinery Capacity
In 2015, average U.S. daily refinery throughput
was 6,207,000 barrels, which represented 20.4%of the global total that year (BP 2016). Thisvalue, 20.4%, was used to scale the data on U.S.
refineries and petrochemical plants to estimate
the size of the global process heat market forthese types of facilities.
GDP Comparison
While petroleum and fertilizer production
facilities had clearly defined production rates
and capacities, this information is not available
for other types of industrial facilities that could
potentially use nuclear energy for process heatapplications. For these industries, we assume theratio of potential process heat applications relative
to the U.S. potential mirrors the ratio of world GDP
to U.S. GDP. In 2015, U.S. GDP was $18,036.65
billion (in U.S. dollars) compared to global GDP of$74,188.70 billion (World Bank 2017). This meansthat the United States accounted for 24.3% of theworld’s economic output in 2015. We used 24.3%
to scale our results for U.S. nuclear process heatpotential in non-refinery industrial applications to
the rest of the world.

WORLD-WIDE NUCLEAR PROCESSHEAT CAPACITY
Using the above-defined scaling factors, weestimate the worldwide potential for nuclear
process heat applications, assuming the use of

Table F.32: Estimate of worldwide nuclear process heat potential assuming 300-MWth reactors
Category

Scaling Factor

Number of Reactors

Supplied Heat Load

Power Plants – Cogeneration
Refineries – Stand Alone
Refineries – Petrochemical
Chemicals – Ethylene Glycol
Chemicals – Vinyl Chloride
Chemicals – Nylon
Minerals – Soda Ash
Pulp and Paper
Other - Food
Other – Cellulose Acetate
Other – Specialty Chemicals

0.243
0.204
0.204
0.204
0.204
0.243
0.243
0.243
0.243
0.243
0.243

1136
162
94
50
30
42
29
173
157
9
9

340,800 MW
48,600 MW
28,200 MW
15,000 MW
9,000 MW
12,600 MW
8,700 MW
51,900 MW
47,100 MW
2,700 MW2,700 MW

Other – Brine

0.243

9

2,700 MW

Process Heat Markets for Generation-IV Nuclear Reactors

203300-MWth reactors, at 570,000 MWth (Table
F.32). This is roughly five times the estimatedmagnitude of the potential domestic U.S. market.

FUEL MARKETS
While the industrial sector accounts for asignificant share of total primary energy use in
the United States, its energy use is less than thatof the transportation sector (21.4 quadrillion Btu
in 2014, compared to 27.0 quadrillion Btu fortransportation) (Figure F.3). The use of nuclear
power to supply transportation sector energy
demand could dramatically expand nuclear
energy’s role in the overall energy mix and thepotential for associated CO2 reductions.
We examine this potential for three scenariosthat assume a major paradigm shift in thetransportation sector, which is currently nearly
100% dependent on liquid petroleum fuels. The
three scenarios assume full replacement of current
transportation-related fossil energy consumption
by electrification, hydrogen fuels, and biofuels,
respectively. We do not consider other potential
synthetic fuel options, such as gas-to-liquids
and CO2-to-liquids. Our methodology compares
the efficiency of these non-petroleum fuels(i.e., electricity, hydrogen, biofuels) to current
conventional transportation fuels to estimate
total transportation energy requirements undereach scenario:
Energy Required by New Fuel =EffNew Fuel

EffCombustion
Other assumptions used for this analysis
are detailed in Table F.33.

ELECTRIFICATIONElectrifying the transportation sector would
involve replacing internal combustion engines
and fuel tanks with electric motors and batteries.
A number of auto manufacturers have recently
released all-electric models (e.g., the BMW i3,
Nissan Leaf, and GM Bolt). Electric cars are much
more efficient than internal combustion cars,
with an average efficiency of 60% (Office ofEnergy Efficiency and Renewable Energy 2015).
If electric cars were to become the norm in the
United States, they would require 2,640 TWh ofelectricity per year to operate.

HYDROGENIf hydrogen were to emerge as the preferred pathto zero-carbon transportation, new methods for
producing hydrogen would be needed, since thecurrent method—which relies on steam methane
reforming—generates CO2 emissions. We
considered two alternative hydrogen production
methods: electrochemical splitting of water andthermochemical splitting of water.

Energy Required by Combustion

Table F.33: Transportation fuel market assumptions

204

Assumption
Average efficiency of the current transportation
fleet is 20% (Office of Energy Efficiency and
Renewable Energy 2015).

Justification
This is the average efficiency ofan internal combustion engine.

Heat to electricity conversion efficiency is 35%.

This is an average heat toelectricity conversion ratio.

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Implication
Does not consider the diversity of thetransportation fleet (e.g., trucks vs. cars).
However, it should give an adequate firstorder approximation.
35% is considered low for higher
temperature heat processes.

At 50%, the average efficiency of hydrogen fuelcells is much higher than that of traditional internal
combustion engines. This means that replacing thecurrent U.S. vehicle fleet with hydrogen-powered
vehicles would require 3,164 TWh per year ofhydrogen gas. Hydrogen gas has a lower energy
value of approximately 121.5 megajoules per
kilogram (MJ/kg) meaning that using hydrogen to
power the U.S. transportation fleet would require
9.375 × 1010 kilograms (kg) of hydrogen per year
(DOE 2006).

Electrochemical Splitting of Water(Electrolysis)
In electrolysis, an electric current is run throughwater to decompose the water into hydrogen andoxygen gas:
2H2O

2H2 + O2

Common industrial-scale electrolysis has anefficiency of around 70% for converting electricity
to hydrogen gas. However, significant research
efforts are underway to develop new technologies
that would improve this efficiency. Using current
electrolysis technology, approximately 574 GW

of electric generating capacity would be needed
to produce enough hydrogen to run the U.S.
vehicle fleet. This level of electrical generation
corresponds to a thermal heat load of 1,630 GW or
5.461 300-MW nuclear reactors.

Thermochemical Splitting of Water
In contrast to electrolysis, where an electric
current is used to split water, thermochemical
splitting uses a chemical looping process toseparate the hydrogen and the oxygen. Currently
the most developed process is the sulfur-iodine
process, which has a thermal conversion efficiency
of approximately 50%. This process has theadded benefit transforming the heat directly
into hydrogen chemically without electric power
input, which allows for efficiency gains. As aresult, this hydrogen production pathway requires
significantly fewer reactors than electrolysis.
However, the thermochemical cycles that havebeen proposed all present technical issues thatmust be overcome. In particular, the sulfur-iodine
process involves the use of sulfuric acid at
approximately 830°C meaning that associatedmaterial problems have to be overcome.

Table F.34: Electrification reactor requirements
Category
Electrification

Number of 300 MW Reactors

Required Heat Load

Required Electricity Load

3,186

956 GW

335 GW

Number of 300 MW Reactors

Required Heat Load

Required Electricity Load

5,461

1,630 GW

574 GW

Number of 300 MW Reactors

Required Heat Load

Required Electricity Load

2,676

803 GW—

Table F.35: Hydrogen – Electrolysis reactor requirements
Category
Hydrogen – Electrolysis

Table F.36: Hydrogen – Thermochemical reactor requirements
Category
Hydrogen – Thermochemical

Process Heat Markets for Generation-IV Nuclear Reactors

205

BIOFUELS
There are two major types of biofuels that involve
different production methods: bioethanol andbiodiesel. Bioethanol is produced by fermenting
sugars from biomass feedstocks, typically sugar
cane or corn, whereas biodiesel is produced
by reacting lipids with an alcohol to produce afatty acid ester. Biofuels are notoriously energy
intensive to make due to the energy required to
extract the necessary components from the cells,
which involves breaking down the cell walls. The‘energy returned on energy invested’ (EROEI) for
conventional biofuels is currently only 1.3, meaningthat for every 1 Joule (J) of biomass energy used
to make biofuels, only 0.769 J are available
afterwards.
Biofuels are used in internal combustion engines;
a full transition to this transportation fuel sourcein the United States would therefore require
7,910 TWh of biofuel energy per year. Applying an
EROEI of 1.3 and assuming that all invested energy
is supplied in the form of heat from a nuclear
reactor, we estimate that 1,305 GW of nuclear
capacity would be required to produce enoughbiofuels to run the U.S. vehicle fleet.

COMPARING DIFFERENTTRANSPORTATION OPTIONS
Our analysis of different pathways to zerocarbon transportation clearly indicates that
thermochemical splitting of water results in thelowest overall energy requirement. This is dueto the high efficiency of hydrogen fuel cell cars
and the high efficiency of converting heat intohydrogen. However, it should be noted that ouranalysis did not consider a number of potentially
important technical issues, for example, materials
issues with the thermochemical splitting of waterand land-use issues with biofuels. There may beother underlying technical or social issues that
discourage or favor one technology choice overanother.
An important observation from Table F.38 isthat the order of magnitude of the heat loads
associated with using nuclear energy to supply
different zero-carbon transportation fuels isroughly ten times that of potential process heatapplications in the industrial sector (roughly
1,000 GW compared to 100 GW). This suggeststhat the transportation sector offers a much larger
potential market for expanding the role of nuclear
power in the future.

Table F.37: Biofuels reactor requirements
Category

Number of 300 MW Reactors

Required Heat Load

Required Electricity Load

Biofuels

4,348

1,305 GW—

Table F.38: Comparison of nuclear reactor requirements for different transportation energy options
Category

206

Number of Reactors

Required Heat Load

Required Electricity Load

Electrification

3,186

956 GW

335 GW

Hydrogen – Electrolysis

5,461

1,630 GW

574 GW

Hydrogen – Thermochemical

2,676

803 GW—

Biofuels

4,348

1,305 GW—

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

CONCLUSION
Our analysis of U.S. industrial facilities that could
be suitable for nuclear process heat applications
suggests that only 16.5% of the entire domestic
industrial heat market could be supplied using
nuclear energy. This is largely because manyindustrial sites use fuel gas by-products andwaste streams as energy sources and because
commercial production of hydrogen currently
requires higher temperatures than nuclear reactors
can provide. Imposing a carbon constraint on
industrial sector emissions would discourage theuse of internally produced fuel gas as an energy
source at industrial sites. It would also require theprocess heat industry to re-engineer many existingprocesses to enable greater integration withcarbon-free energy sources—with the net effect of
creating a larger market for nuclear energy.
Another potential future market for nuclear energy
is the production of electricity or synthetic fuels
for the transportation sector. This potential issubstantial—and could be more than an orderof magnitude larger than the potential in theindustrial heat market.

Process Heat Markets for Generation-IV Nuclear Reactors

207

REFERENCES
BP. 2016. “BP Statistical Review of World Energy June
2016.” London: BP.
Haussinger, P., R. Lohmuller, and A. Watson. 2011.
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Hydrocarbon Publishing Company. 2012. “Refinery
Energy Management – Latest Technologies andStrategies to Enhance Operational Economics.” http://
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Idaho National Laboratory. 2011. High Temperature
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Konefal, J. and D. Rackiewicz. 2008. Survey of HTGR
Process Energy Applications. Washington D.C.: MPR
Associates Inc.
Midland Cogeneration Venture. 2017. “Combined
Cycle Technology.” July 7. http://www.midcogen.com/
combined-cycle-tech.php.
MPC. 2017. “Texas City Refinery: Texas City, Texas.”
http://www.marathonpetroleum.com/Operations/
Refining_and_Marketing/Refining/Texas_City_Refinery.
Nelson, L., A. Gribik, V. Maio, M. McKellar, M. Patterson,
and R. Wood. 2010. Integration of High Temperature
Gas-Cooled Reactors into Industrial Process
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Office of Energy Efficiency and Renewable Energy.
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evtech.shtml.
Reimert, R., F. Marschner, H.J. Renner, W. Boll,
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U.S. Department of Energy. 2006. “Hydrogen Fuel
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Ullmann’s Encyclopedia of Industrial Chemistry, 465-526.
Weinheim: Wiley.

Appendix G

Results from a Survey of Development,
Demonstration, and Deployment
Paradigms in Other Industries
To gain insight into issues surrounding the commercialization of a new generationof nuclear energy technologies, we surveyed the development, demonstration, anddeployment paradigms followed by other industries in introducing a diverse set of newtechnologies and products. Specifically, we conducted a series of surveys with experts
from similarly technology-intensive industries in the United States, including chemicalplants, coal plants, offshore oil and gas, jet engines, pharmaceuticals, automobiles,
satellites, and robotics. The goal was to compare the deployment of nuclear energy
technologies with deployment patterns in other industries, identify similarities anddifferences, and ascertain if there are strategies that could be adopted by the nuclear
energy industry to reduce the long timescales and high costs of new product deployment.
(Not all interviewees answered all questions, but the list of questions was broad enoughto elicit information relevant to our study.) Based on the interviews, we grouped various
technologies and identified ranges of cost and deployment timescales for the different
industries surveyed. We summarize our findings and synthesize important characteristicsof these industries in the last sections of this appendix.

TECHNOLOGY GROUPINGS
We grouped the industries in our survey using thefollowing criteria and characteristics:• Large scale (LS)—Industries that produce
technologies that are physically large and that
often have to be assembled on site for thisreason; in other words, comparable in size tonuclear plants.
• Extensive R&D and Regulation-Driven
Testing (ERD)—These industries spend a
disproportionally large amount of time building
models, testing modules, or conducting
demonstrations; performing extensive testing;
and working closely with regulatory bodies.

• High Returns (HR)—Industries whose
products’ marginal cost is far lower than theirmarket price and industries that sell a highvolume of products. These tend to be thecommercial industries and the industries withthe most freedom for innovation.
• Factory Fabrication, Modular Construction,and Strong Supply Chains (FF)—Industries
that are able to optimize cost by minimizing theneed to build on site; in other words, industries
that have achieved some of the deployment
efficiencies that are important for the successof advanced nuclear technologies.

Results from a Survey of Development, Demonstration, and Deployment Paradigms in Other Industries

209TIME AND COST RANGESFOR TECHNOLOGY DEPLOYMENTBased on interviews with industry experts, thetime and cost ranges1,2 needed to deploy newtechnology in different industries are shown in
Table G.1 and pictured in Figure G.1. Figure G.1
shows the results of a deeper analysis of cost
and time trends for the three major phases—
research and design, testing/demonstration, anddeployment—across all the technologies surveyed.
Table G.1: Time and cost ranges for new technology
deployment in different industries
Industry

Time (years)

Nuclear

18–30

Cost ($B)
10–16

Chemical

10–15

3–10

Airplane Engines

10–15

3–5

Pharmaceuticals

9–15

1.6–2

Satellites

9–10

1–3

Automobiles

3–5

1–1.5

Coal

3–5

1–1.25

Offshore Oil

3–4

0.01–1

Small Robotics

2–3

0.03–0.04

The industries with the longest development
times (nuclear, chemical, airplane engines,
pharmaceuticals) all spend proportionally very
little time in the technology deployment phase.
Instead they focus most of their time in thetesting/demonstration phase. This correlateswith the fact that these are also the industries
that must answer most extensively to external
regulators (excluding the chemical industry).
The nuclear industry works closely with the
U.S. Nuclear Regulatory Commission (NRC),
airplane engine manufacturers work with
the Federal Aviation Administration (FAA),
and the pharmaceutical industry interacts
heavily with the Food and Drug Administration(FDA). The chemical industry is a unique casein that it is mostly self-regulated, althoughchemical companies must interface with the
U.S. Environmental Protection Agency (EPA).
Nonetheless, the chemical industry undertakes
a complex, multiphase testing process that often
involves building a string of small-scale, but fully
functional and producing, demonstration facilities.

Figure G.1: Proportional amount of time (left) and budget (right) that different industries spend in each phaseof new technology development.
Normalized Cost Per Development Phase

Normalized Time Spent Per Development Phase
100%

100%

90%

90%

80%

80%

70%

70%
60%

60%

50%

50%

40%

40%

30%

30%

20%

20%

10%

10%

es
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Ai
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Technology Deployment

Nu
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Research and Design

l

0%

0%

Testing/ Demonstration

Technology Deployment

Values and ranges as predicted from interviewed experts.

1	The large ranges of costs are correlated with industries that produce highly varied products, such as satellites,
chemicals, and offshore oil.

2

210

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDThe need to build these small-scale facilities isreflected in the disproportionately large amountthat chemical companies spend in the testing/demonstration phase of new product deployment.

• Deployment consists of building a commercialscale facility (6 years to construct).

Most of the new product deployment expenses
incurred by the more cost-intensive industries
are not all associated with the same development
phase. The chemical industry accrues large
expenses to construct demonstration plants(testing/demonstration); the automobile industry
spends much of its product development budget
on developing new production lines (technology
deployment); most of the cost of deploying new
pharmaceuticals is associated with the many
rigorous and expensive clinical trials needed toverify the performance of new drugs (testing/demonstration); and the bulk of the cost of
deploying a new offshore oil rig is purely driven
by capital costs for rig construction (technology
deployment).

This industry is largely self-regulated, but EPA,
local ordinances, and other parties regulate afacility’s environmental impact (e.g., emissions).
Permits are required to install and operate thesefacilities.

SUMMARY OF ALL INDUSTRIESSURVEYED
Chemical Facilities (LS)
Chemical facilities vary enormously dependingon the nature of the product(s) they produce.
Therefore, the cost to develop one of thesefacilities is also very variable, ranging between$3 billion and $10 billion. Large chemical projects
are always built using existing technology; newdesigns are usually derivative or copy existing
technologies to reduce cost and the probability ofan accident.
Deployment Phases• Research can take up to 2–10 years.
• Demonstration consists of building
small-scale facilities. Pilot scale facilities($5–$50 million capital investment; 2 years
to construct, operated for 2–4 years) andmarket development facilities (larger sites
to demonstrate cost and scale; 2–4 years ofconstruction). Major blunders tend to occur
only in the smaller, pilot-scale projects.

Regulations and Safety Assurance

Airplane Engines (LS, ERD)
New engine designs are based on a prediction ofwhat airlines will need 10–15 years into the future;
the engines can only be created if the industry
is confident there will be an aircraft for it to go
on. Quite often, the aircraft design is incomplete,
which necessitates an iterative design processwith the engine framer. This deployment paradigm
can be quite restrictive to innovation, because
the airplane frame places physical shape and size
constraints on the engine.
Airplane engines are sold to airframe makers at
prices that are lower than cost of constructing theengine. Engine manufacturers only begin to makenet positive profits by servicing and maintaining
the engines. This unique business model has seena recent paradigm shift.
Deployment Phases• The research and development (R&D) phase
involves establishing a new idea, convincing
executives and airplane makers that the idea
is worthwhile, and flying a demonstration
model (the demonstrator is a proof-of-concept
engine). The demonstration model falls justshort being a prototype in that it displays only
the unique and new components of the engine(2–4 years, $150–$250 million).
• Individual components and subsystems aretested years in advance as well. Prior to theconstruction of the demonstrator, engine
makers run simulations (computer models
based on first principles) to test various
concepts.

Results from a Survey of Development, Demonstration, and Deployment Paradigms in Other Industries211• Testing and demonstration: Flight testing (1–2
years)• Technology deployment: Companies
incorporate the engine into the airframe (1–2
years), and develop the final product, including
detailed engineering and certification (5–6
years).
Budget• Idea development costs: ~$100–$200 million• Construction of demonstrator: ~$50 million• Detailed engineering and certification:~$1 billion
Regulations and Safety Assurance
Certification is gained through the FAA. The
FAA requires manufacturers to build a set of
approximately 15 engines on which they canconduct tests. Manufacturers need to demonstratethat the engines can (a) operate for an extended
period under a set of conditions and (b) operatesafely under destructive failure situations

Pharmaceuticals (ERD, HR)
Developing a new drug and bringing it to market
takes, on average, about 14 years (Schuhmacher,
Gassman, and Hinder 2016). Within the market
there is a large amount of competition, but also
simultaneous camaraderie, amongst companies.
The venture capital model is one of the mostprevalent in the pharmaceutical industry. Because
smaller companies tend to have more freedom toinnovate, larger companies often purchase a new
product after a patent has been issued. Smaller
companies benefit from this dynamic because
they need the resources, expertise, market, andbrand name of larger companies to deploy theirinnovations.

Deployment Phases• R&D: Discovery and development (4.5 years)
covers the period during which research into
a new drug begins in the laboratory. This
early work is often carried out by universities
or public research organizations. It is often
preceded by a pre-discovery stage, when
researchers work to understand a particulardisease. The pre-discovery stage is often
followed by drug discovery phase, in whichscientists identify a way to combat the disease.
Scientists may look at thousands of options
before finding one that is effective.
• Testing/demonstration: New pharmaceuticals
undergo an intensive, multi-stage series of tests
that begin with preclinical research (1 year),during which the drug undergoes lab testing (invitro) and animal testing (in vivo) to determine
its safety. Preclinical trials are followed byclinical research, during which the drug istested on human subjects. Typical clinical
trials consist of three stages that progressively
increase in size, complexity, and time (1.5, 2.5,
and 2.5 years respectively).
• Technology deployment (18 months): In
this phase, the manufacturer submits anapplication to the FDA requesting permission
to market a drug. The FDA review process takes
approximately 6–10 months.
Budget• Drug discovery and preclinicaldevelopment: 33%• Clinical development: 63%• Submission to FDA: 5% (Schuhmacher,
Gassman, and Hinder 2016)
Regulations and Safety AssuranceThis entire drug development process is carefully
monitored and reviewed by the FDA. Before
companies can progress from preclinical to clinical
trials, they must submit a detailed application
to the FDA. The review of this application takes

212

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDabout 30 days. Because the testing/demonstration
process for this industry is extremely rigorousand costly, only about 1 in 5,000 drug candidates
makes it to the licensing phase.
Following approval of a new drug application(NDA), the FDA also monitors drug safety
once the drug is available for use by the publicand conducts inspections on the facilities that
manufacture the drug. At any point, the drug
developer can ask for help or technical assistancefrom the FDA. The FDA also consults withcompanies to determine the best methods ofconducting trials.

Satellites (FF)3
Costs to deploy satellite projects are extremely
variable due to the large differences in projecttype and complexity. Typical costs range from
$10 million to $1 billion. The deployment of newsatellites tends to take approximately 10 years
from concept to launch, with wide variations.
Deployment Phases• R&D: The National Aeronautics and Space
Administration (NASA) has coined the term
‘project formulation’ to describe the two phases
in which a project’s requirements, including
estimates of cost and schedule, and systemdesigns are defined. In the first phase, Phase
A (‘concept and technology development’),
new technologies are identified and plans fortheir development, the use of pre-establishedtechnologies, and plans for risk-mitigation andtesting are formulated. In Phase B (‘preliminary
design and technology completion’), moredetailed plans are developed regarding various
program requirements. This two-phaseproject formulation period concludes witha preliminary design review, in which the
project must demonstrate that it can meet all
system requirements within cost and schedule
constraints.

3• Testing/demonstration: A major review, theKey Decision Point C (KDP-C), is conducted
to assess the preliminary design and makea determination concerning the project’s
readiness to proceed to the next phase. This
review is completed by independent experts
who provide an assessment of the project’s
technical and programmatic approach, projectrisks, and progress. Following this review, theproject proceeds to Phase C, during which thedesign is finalized, test units are fabricated, andcomponents are tested. A second design review
occurs in the latter half of Phase C.
• Technology deployment: In Phase D,
systems are integrated and other supporting
infrastructure is completed. System assembly,
integration, test, and launch activities
are also part of Phase D. Phases E and F
consist of operations and sustainment andproject closeout.
BudgetCosts are variable and typically range between$1 and $3 billion depending on the scope of
the project and requirements for the satellite.
Research and design can take approximately
one-third of the total time, and testing another
25% of the time, with the remainder used for
actual demonstration.
Regulations and Safety Assurance
Most of the satellite development process isinternally regulated, and there are not many
externally imposed regulatory requirements (onlyradio frequency (RF) spectrum allocation, RF
interference, and nuclear safety if radioisotopic
power sources are used). There are a variety ofhold points in the project development process,as specified in NPR 7120.5, as well as NASASpace Flight Program and Project Management
Requirements (2012), milestone reviews, and key
decision points where projects or programs can becancelled, not confirmed, restructured, etc.

Data and information pertaining to research satellites.

Results from a Survey of Development, Demonstration, and Deployment Paradigms in Other Industries

213

Similar to the nuclear industry, satellites arealso subject to requirements for workmanship,
electronic components, materials, and technicalprocesses to determine the flight-qualityof hardware and software. These stringent
requirements increase the time and cost necessary
for project completion, but are necessary to ensure
the success of the satellite.

Automobiles (HR, FF)
The automobile industry is a leader in mass
production. One of the methods it uses to facilitate
mass production is maximizing the standardized
components of a vehicle. Components that
customers do not see are simplified and madeuniform within a company, and only externallyvisible features are modified. This approachfacilitates mass production and reduces
development costs.
Deployment Phases

Regulations and Safety Assurance
During the preproduction phase, safety, emissions,and crash testing and safety compliance begin.
Self-testing of components occurs prior to thispoint. Although some standards are defined at thefederal level, different regions have different setsof requirements. Within the United States, there
are specific official testing locations that normalize
the testing done to demonstrate compliance withindustry regulations. Because of the regionalityof these requirements, manufacturers often haveto modify their car designs for different regions;
therefore, the supply chain is often formed
locally as well. Most testing does not begin until
the entire car is fully assembled. Additionally,
all manufacturing facilities must comply with
Occupational Safety and Health Administration(OSHA) regulations.

Coal Plants (LS)
Budget• R&D: Research is considered to be anything
conducted 10 or more years before a carreaches the dealership. During this phase,the concept of the car is being developed.
Advanced engineering is the work conductedto bring the concept to reality 3–5 years prior
to completion. In this phase, individual vehicle
components are being developed.
• Testing/demonstration: Preproduction,
which occurs in the last two years prior to
manufacturing, describes the period when theentire vehicle has been integrated and built.
This is also the period when the manufacturer
conducts testing and qualification at the vehicle
level.
Budget• Research: 5%–10%• Testing/demonstration: 30%• Fabrication: 60%

214

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

The coal-fired power plant industry benefits
from the maturity of the technology and the
predominant use of a standard design (thisindustry has little need for first-of-a-kind
technology). Thus, the vast majority of deployment
costs occur in the procurement and construction
phase, a three-year process, in most cases, thatdemands roughly $1 billion of investment. Coalplant designs also include elements of modularity.
Engineered equipment such as turbines andgenerators are catalog items, and pieces of large
equipment are often prefabricated at the vendors’
facilities. In some cases, full standardization is notpossible because of site-specific adaptations for aparticular application.
Regulations and Safety AssuranceThis industry mostly works with the EPA andlocal regulatory commissions, which monitor
and regulate air and water quality. In addition tofederal regulations, each state has its own set ofenvironmental regulations.

Offshore Oil Platforms (LS, HR)
In the offshore oil industry, there is little innovation
regarding the technology used at the surface, andevery effort is made to use existing technologies
in an effort to reduce cost. Additionally, rig
design can be heavily influenced by previously
completed rigs located in similar environmental
settings, and the industry can rely on the researchand construction abilities of the well-establishedship-building industry. Within this industry,
offshore projects tend to be declared finishedon time, though they are often only partiallycomplete when this occurs (this tendency is likely
a result of the high pressure to begin producing
immediately). In these cases, costly offshore
work is often required to finish the project.
The tendency to rush declarations of projectcompletion is problematic because, once the rig
is out of the shipyard, it becomes much moredifficult and expensive to continue working on its
construction.
Deployment Phases• R&D: This phase includes concept selection,
FEED (‘front end engineering design’), anddetailed design. During concept selection,a concept is developed for the best generalapproach to producing the oil (6–8 months).
The design requires a look from end to
end—that is, from the reservoir to the market.
Then, in FEED, the primary goal is to narrow
down options and better define the project.
A FEED package may include 500–1,000
drawings and reports that address all the
major parts and systems of a facility. A typical
FEED may last 8–18 months. Finally, in detailed
design, the company completes all the workneeded prior to construction (e.g., prepares
operations manuals, writes commissioning andtest procedures, settles on final design). The
detailed engineering phase occurs in the 6–9
months before construction commences.

• Technology deployment: Typically, theconstruction of offshore rigs involves the use ofan engineering, procurement, and construction(EPC) contract, with the owner’s engineeringand operations team providing oversight andinsight (24–36 months). The construction
process is largely modularized, and many
activities occur in parallel to facilitate the rapid
construction of such large-scale projects. Large
platform hulls are constructed and assembled
in drydock or dockside. Other modules arebuilt in a separate yard, and are lifted onto thecompleted hull and connected afterward.
Budget• From end to end, engineering is only about 15%of the total budget.
• Project management expenses account for~20% of the total cost.
• Remaining costs are associated with facility
construction.
Regulations and Safety Assurance
Oversight organizations focus on both
environmental safety and personnel/facility
safety. The offshore oil industry is regulated in
the United States by the Bureau of Ocean Energy
Management (BOEM), which oversees the
management of resources and the collection ofroyalties and which manages the government’s
leasing process for awarding drilling rights. The
industry is also regulated by the Bureau of Safety
and Environmental Enforcement (BSEE).4 Different
regulations apply in different parts of the world.
Therefore, depending on where the rig is to bebuilt and located, the company must consider
different limitations and approaches. Testing is
conducted at the vendor/factory level to ensurecomponent quality and functionality. Following hullassembly, further tests are performed to validate
the functionality of the completed unit as well as
material and welding tests.

	Following the Deepwater Horizon spill of 2010, the MMS (Minerals Management Service) was renamed the
Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) and separated into three groups:
the Office of Natural Resources Revenue, the BOEM, and the BSEE.

4

Results from a Survey of Development, Demonstration, and Deployment Paradigms in Other Industries

215

Small Consumer Robotics (HR, FF)

SYNTHESIS OF RESULTS

Because of the small scale of consumer robotics
technology, this industry is able to take a vastlydifferent approach to deploying new products.
From the outset, product development can becompleted in a more integrated and dynamic
fashion and because the level of complexity
involved is more manageable, operations andengineering can be merged earlier in the process.
This integrated systems approach is advantageous
because it facilitates a shorter deployment period
and allows for early detection of any incongruities
between systems.

Our interviews with experts from other industries
helped us identify a number of key attributes
that could help accelerate the development,
demonstration, and deployment of new nuclear
energy technologies and increase the commercial
attractiveness of these technologies. They aresummarized here.

Deployment Phases• R&D (12–24 months): This phase involves
conducting market research and testing ideas
by building many prototypes. A few whole,functional robots may be built, but only to
conduct testing of specific ideas.
• Testing/demonstration (12 months): In thisphase, prototypes are continuously being
constructed, but with better materials.
Validation of a final prototype and integration
tests are completed. The construction process
is slowly moved to a factory.
• Technology deployment and manufacturingramp process (3 months): The volume of
products produced is incrementally increased
over the course of 3–5 weeks. Products areshipped out.
Budget• The budget allocated to each phase is roughly
proportional to the time it takes.
Regulations and Safety Assurance
Consumer products are generally regulated
by individual government agencies (unique tothe country they are being sold in) and (in the
United States) at the state level to assure safety,
reliability, and performance. Manufacturers usually
begin submitting material for regulatory approval
3–6 months ahead of production.

216

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Increase Intrinsic and Extrinsic Valueof Product
When a higher value is associated with a given
project there is greater incentive to complete theproject as quickly as possible and greater incentive
for investors to provide funds. Payment of apremium for electricity generated from nuclear
energy might be mandated by CO2 reduction
policies and the potential for additional energy
applications could also add value to the watts
produced by nuclear facilities.

Reduce Product Size and Complexity
Scale-backs in complexity correlate with
reductions in the amount of labor required tocomplete a project and with reductions in thepossible contingencies/failure points that canoccur. Passive safety features in many advanced
reactor designs are conducive to smaller andsimpler designs.

Modularize Technology
Modularity permits increased construction in
efficient, controlled, and predictable environments(factories)—all of which should reduce cost andpotential for failure. The technologies includedin the FF group provide an indication of the scalerequired for advanced nuclear systems to beeffectively modularized.

Standardize Design (Nth-of-a-Kind
Technology)
It is interesting to note that coal-burning electricity
generation is one of the most cost- and timeefficient industries we surveyed, even though
it does not fit into the trends that describe thedeployment effectiveness of other industries.

Because this industry has been able to test anddeploy a well-established design, there is nolonger much incentive to innovate or reimagine thetechnology. Thus, the resources usually allocatedto R&D and testing/demonstration are not needed.
The coal industry is a clear example of the benefitsof working with nth-of-a-kind technology.

Formalized Effective Project Management
Structure

There is a potential flaw in a deployment modelthat aims to design systems that can answer for all
potential eventualities. The risk is that this model
diverts the focus from the primary objective:
producing a functional product. Therefore, it isimperative for the nuclear energy industry to findan optimal balance in new reactor designs that
do not compromise either safety or development
and that successfully reduce facility size, cost,and complexity.

Many of the low-cost industries were able toidentify adherence to strong project management
techniques and the use of strong developmental
benchmarking as primary contributors to
deployment cost reductions. Because thedeployment of a new technology often involves
large and complex projects, an imposed structureassists with efficiency, organization, and clarity.

Construction of Small Demonstrator
Facilities
Although the cost, timescale, and physical sizeof chemical facilities is comparable to that ofnuclear facilities, the chemical industry is still able
to construct physical, small-scale demonstrator
facilities that allow for expedited testing andregulation (often, these smaller facilities areeven able to generate a small amount of revenue
through sales of their product outputs).

Regulatory Reform
None of the individuals we interviewed regarded
their industry as being subject to overly
burdensome regulation—indeed, some evenconfessed to thinking that the regulatory systemthey operated under was lacking. This contrasts
with common industry opinion regarding theregulation of nuclear energy facilities. Strong
relationships between the industry and regulatory
authorities and regulations that are relevantto specific technologies and do not preclude
innovation/development are critical to minimizing
the resources that are devoted to the testing/demonstration phase.

Results from a Survey of Development, Demonstration, and Deployment Paradigms in Other Industries

217

REFERENCES
National Aeronautics and Space Administration. 2012.
“NASA Space Flight Program and Project Management
Requirements.” Accessed 2017. https://nodis3.gsfc.nasa.
gov/displayDir.cfm?t=NPR&c=7120&s=5E.
Schuhmacher, Gassman, and Hinder. 2016. “Changing
R&D models in research-based pharmaceuticalcompanies.” Journal of Translational Medicine April 27,
14(1):105.

218

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix H

Measuring the Cost of Recent New
Nuclear Power Plant Builds
This appendix provides additional background and detail concerning factors behind thehigh cost of recent new nuclear power plant builds.
Before discussing specific projects, a note on
handling cost numbers is in order. ‘Overnight
cost’ is a standard industry metric for quoting
the capital cost of electric generating plant
alternatives. This is the cost of building theplant as if it could be built instantly—that is,using current prices and without the additionof finance charges related to the time requiredfor construction. Another metric is ‘investment
cost,’ which includes the effect of inflation andfinance charges up to project completion. Finally,the ‘levelized cost of electricity’ (LCOE) is a unit
cost metric, which allocates the capital costto electricity output over the life of the plant
and adds in operating and maintenance costs,
including the cost of fuel. We focus primarilyon overnight cost, denominated in U.S. dollars
and qualified by the year for which it is quoted,
because we find this metric sufficient forunderstanding and addressing the issues at hand.
When we mention another metric, it is only to tie
back to how the figure was originally reported in
the source material. While construction delays
add costs on top of the overnight cost, in the formof inflation and financing charges, we address thatby simply noting the reality that delays occur.
Many public sources report cost figures in a sloppy
fashion, without distinguishing clearly between
overnight or investment costs or even assuringconsistency in the items included. For example,
some sources report just the cost of the contract
between the vendor and the buyer/owner, wherea proper economic evaluation should include theadditional construction-related costs incurred
directly by the owner. Indeed, reported figures
for the cost of constructing comparable nuclear
plants can vary by a factor of two or more (Duand Parsons 2009) (Deutch, Moniz, et al. 2003).
Therefore, we avoid reporting some headline
figures for which definition is lacking, and we focus
instead on the smaller set of sources that provide
clearly detailed figures.
We begin by anchoring our discussion with afigure from the 2009 update of the MIT 2003
Future of Nuclear Power study. The 2009 update
estimated the “plausible, but not yet proven”
overnight cost of a Gen-III+ nuclear plant in the
United States at $4,000 per kilowatt (kW) in2007 dollars, which is roughly $4,900 in 2017
dollars. Emphasizing the conditional nature of theestimate, the 2009 study stated:
The challenge facing the U.S. nuclear industry
lies in turning plausible reductions in capitalcosts and construction schedules into reality.
Will designs truly be standardized, or willsite-specific changes defeat the effort to drive
down the cost of producing multiple plants?
Will the licensing process function without
costly delays, or will the time to first power be
extended, adding significant financing costs?
Will construction proceed on schedule andwithout large cost overruns?

Measuring the Cost of Recent New Nuclear Power Plant Builds

219

The first few U.S. plants will be a critical test for
all parties involved.1

One of the earliest Gen-III+ designs to begin
construction in the west is the EPR (originally theEuropean Pressurized Reactor, and now simply theEPR), which was developed by the French stateowned company Areva together with the German
firm Siemens.2

The actual experience with the first few builds ofthe new Gen-III+ designs in the United States andWestern Europe failed that test spectacularly. The
projects have experienced long delays and large
cost overruns. We discuss this recent experience,
providing cost information, construction duration
information, and a few historical details. Table H.1
summarizes the key data. These are the data thatare summarized in Figure 2.3 in Chapter 2.

• In 2003, a deal was struck to build the EPR at
Olkiluoto, Finland with a 4.5-year construction
schedule set to begin in 2005 and becompleted in 2009. While construction did
begin in 2005, the project has experienced
a seemingly unending series of delays, withthe completion date last reported to be 2019,a full decade later than originally planned.3
In 2003, the reported cost of the deal was€3.2 billion ($3.8 billion). As of December

In reviewing reported costs, we translate all data
to an overnight cost quoted in 2017 dollars. Ourreview is organized by the major reactor vendors
and designs.

Table H.1: Overnight cost of recent Gen III+ builds versus benchmark
As ReportedYear$ TotalEquivalent Overnight Cost
$/MWh

Year

Benchmark fromMIT Update

MonthsConstr.

2017 $

Overnight
$/MWh
Share

Inflation
Factor

$/kW

4,000

1.219

4,900

2007

EPR
Olkiluoto

2012

11.12

6,822

2003

174

55%

3,769

2.122

8,000

Flamanville

2007

12.60

7,636

2007

126

79%

6,042

1.219

7,400

2012

26.01

8,128

2012

72

93%

93%

1.104

8,400

Vogtle 3&4

2007

19.19

8,591

2012

104

91%

7,800

1.104

8,600

V.C. Summer 2&3

2007

11.77

5,265

2007

94

100%

5,265

1.219

6,400

2010

18.60

3,457

2010

54

3,457

1.149

4,000

TaishanHinkley C
AP1000

APR1400
Shin Kori 3
Barakah (UAE)	In employing the “plausible, but not yet proven” description, the 2009 “Update” was reinforcing an assessment
first established in the original MIT Future of Nuclear Power study (Deutch, Forsberg, et al. 2009).
2	Siemens eventually sold its stake to Areva. Recently, Areva was reorganized and the nuclear power plant business
was made a part of the French state-owned company Électricité de France (EDF) and rebranded as Framatome.
3	All construction start and completion dates reported here are as reported in the IAEA’s PRIS database, and where
their “commercial operation date” is used here as the completion date. Actual expenditures on the developmentof a nuclear plant can begin years before major construction expenditures, sometimes even including certain bitsof construction on auxiliary buildings or facilities. A canonical metric for the start of the project is the first pour ofconcrete for the reactor building which usually initiates the intensive investment schedule.
1

220

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

2012, the reported cost had been updated to€8.5 billion ($11.12 billion), or 2.6 times theoriginal estimate. For comparability purposes,
we translated this figure to an overnight cost,backing out the effect of the construction
schedule and an assumed inflation rate.
We then translated this overnight cost to2017 dollars for comparability with the MIT
benchmark. The last reported cost projection
is approximately equal to an overnight cost of$8,000/kW quoted in 2017 dollars, far above
the MIT benchmark.4 Recall that this dramaticincrease in the forecasted overnight cost does
not incorporate the increased financing costcreated by the decade-long construction delay.
Moreover, the latest public cost estimate isfrom 2012, and a recent figure is certainly
much greater.
• In 2004, the second project was announced
for a plant in Flamanville, France, which is
being constructed by Électricité de France(EDF). Construction began in 2007 and was
originally to be completed in 2012. However,this project, too, has experienced enormous
delays and is now scheduled to be completed in2018 at the earliest, six years late. The originalreported cost was €3.3 billion ($4.2 billion).
As of January, 2018, the reported cost had
been updated to €10.5 billion ($12.6 billion),or approximately three times the original
estimate. Once again translating this yields
an overnight cost of $7,400/kW quoted in2017 dollars, again far above the MIT 2009
update benchmark.5• In 2007, a deal was struck for construction
on two units at Taishan, China.6 Construction
began in 2009, with the first unit originallyscheduled to be completed by the end of 2013
and the second by the end of 2014. This project,

too, has experienced significant construction
delays totaling at least four years, with the firstunit now scheduled to be completed sometimein 2018 and the second in 2019. While there
are press quotes on the cost of the original
deal, there is no information about what isincluded in the accounting, so we cannot
reliably translate the available numbers to acomparable overnight cost figure.
• In 2016, the long discussed Hinkley Point C
project, in the United Kingdom was approved
both by the contractor, EDF, and by the British
state. The two-unit facility would be two-thirds
owned by EDF and one-third by the China
General Nuclear Power Group (CGN). Much
preparatory work had been done prior to thatdate, but the official start of construction wasthen scheduled for 2019 with completion of
the first of two units in 2025 and the second
15 months later, in 2027. In 2013, when EDF
and the British government signed a powerpurchase agreement for the project, theovernight cost of the project was reported tobe £16 billion ($26 billion) in 2012 currency, or$8,100/kW. Translating this yields an overnight
cost of $8,400/kW quoted in 2017 dollars,
once again far above the MIT 2009 update
benchmark. The contract provided a firm,
inflation-indexed purchase price for the first
35 years of generation, equal to £92.50/MWh($150/MWh). A price that high is consistent
with a $7,000/kW overnight cost quoted in2012 dollars, depending on assumptions aboutcapacity factor, fuel and other operating andmaintenance costs, and discount rate.
Westinghouse, then a subsidiary of Toshiba,
created one of the earliest Gen-III designs with its
AP600 reactor, but the design was never built. The

	The reported figures are from press reports based on Areva releases. The original figure is taken from a Reutersreport, August 17, 2017, and the latter from the Finnish paper Helsingen Sanomat, December 13, 2012. Information
on how costs are quoted is from the report of the French auditor, Cours des comptes, January 2012, The costsof the nuclear power sector. We have made our own assumptions on inflation based on the MIT 2009 Update
through 2007 and 2% thereafter.
5	The reported figures are from press reports based on EDF releases. The two figures are taken from Dow Jones
reports on April 11, 2007 and January 8, 2018. Translation to overnight cost uses the same methodology andadditional assumptions as for the Olkiluoto plant, adjusting for plant data.
6
	The plant owner is a joint venture of EDF and China Guangdong Nuclear Power Corporation, now China General
Nuclear Power Group (CGN).
4

Measuring the Cost of Recent New Nuclear Power Plant Builds

221company followed up with a Gen-III+ design, theAP1000, which was approved by the U.S. Nuclear
Regulatory Commission (NRC) in 2005 andselected for a number of U.S. new reactor projects
and many elsewhere. Most have not moved
forward, but there is experience with two projects
in China and two in the United States.
• The first two projects to begin construction
were in China. Both units of the two-unit
Sanmen project were begun in 2009, andcompletion was originally anticipated to be
in 2014. The two units of the Haiyang project
were begun in 2009 and 2010, and completion
was originally anticipated to be in 2014 and2015. Completion of both projects has regularly
been delayed, and as of the start of 2018, only
Sanmen Unit 1 is now operational. That is adelay of more than three years. No reliable
cost data are available.
• In the United States, the Southern Company’s
subsidiary Georgia Power proposed two
AP1000s as Units 3 & 4 of the Vogtle plant.
Georgia Power would own 45.7% of the twounits, with three other public power companies
owning the remainder. The proposal wasapproved in 2008 by the Georgia PublicService Commission. As originally conceived,
construction would begin in 2011, withcompletion of the first unit in 2016 and thesecond in 2017. After various other proceedings
were completed, construction actually began
in 2013. As of the start of 2018, construction
is running more than three years behindschedule with a projected completion date forthe first unit in late 2021 and the second unit
in 2022.7 The original costs quoted for the
project translated to an estimated overnight
cost of approximately $4,300/kW quoted in2007 dollars. The most recently updated costprojection shows an updated cost of$8,591/kW in 2012 dollars. Putting thesecosts on a comparable basis yields a revised
overnight cost of $8,600/kW quoted in 2017
dollars.8 It bears repeating that this near
doubling of overnight cost does not incorporate
the added financing costs produced by thelengthening of the construction schedule.
• Throughout early 2017, Westinghouse’s parent
company, Toshiba, was facing a number ofproblems from the cumulative losses on its
various nuclear builds as well as financial
problems in other businesses. Mid-year,
it decided to cap its losses and exit thenuclear construction business and to harvest
what it could by selling the engineering anddesign component that is the Westinghousesubsidiary. It put Westinghouse into bankruptcy
and opened negotiations with the project
owners. Confronted with this, Southern
Company decided to take over responsibility
as the general contractor for the project andnegotiated financial terms with Toshiba. The
Georgia Public Service Commission approved
the decision to continue. Westinghouse has
subsequently been purchased by Brookfield
Asset Management, a private equity firm.
• The other U.S. AP1000 project was for Units 2& 3 at the V.C. Summer plant owned by SCANA
Corporation’s subsidiary, South Carolina
Electric & Gas Company (SCE&G). SCE&G
would own 55% of the project with the state’s
public corporation, known as Santee Cooper,
owning the minority interest. Approved in2008 by the Public Service Commission ofSouth Carolina, construction was to begin in
2011, with completion of the first unit plannedfor 2016 and the second in 2019. The U.S.
NRC’s approval of a construction license camethrough in 2012 and the first unit’s completion	Original dates from Georgia Power’s application for certification of the units and its updated integrated resource
plan, filed with the Georgia Public Service Commission in August 2008. Revised completion dates from Georgia
Power’s Vogtle Construction Monitoring Report, August 2017.
8	Du and Parsons (2009) had estimated $4,700/kW based on partially redacted numbers in Georgia Power’s 2008
submission. Georgia Power’s 2017 filings separate out construction and financing costs in the original submission,
which yields the original figure here. Georgia Power’s 2017 filings give a revised construction cost figure of
approximately $8,591/kW but including inflation during the period of construction which should not be included inan overnight cost number.
7

222

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDwas accordingly adjusted to 2017.9 This project,
like the others, ran into cost overruns andconstruction delays. In 2016, the latest in aseries of schedule revisions moved completionof the first unit to 2019 – a cumulative delay of
approximately two years. Problems continued
to mount, however. In mid-2017, when Toshibaput Westinghouse into bankruptcy, the pairof buyers ultimately decided to abandon the
project despite considerable sunk costs. The
original costs quoted for the project translated
to an estimated overnight cost of approximately$3,400/kW quoted in 2007 dollars. The mostrecently updated cost projection shows adoubling of costs, including inflation over time.
Putting these costs on a comparable basis
yields a revised overnight cost of $6,400/kW
quoted in 2017 dollars. This is a stale costestimate that does not include the update,
which precipitated the project’s abandonment.10
The joint venture GE-Hitachi Nuclear Energy
produced the Gen-III+ ‘economic simplified boilingwater reactor’ (ESBWR) design. This design is a
successor to General Electric’s Gen-III ‘advanced
boiling water reactor’ (ABWR) design, which wasused in a series of four builds in Japan between
1996 and 2006, including units 6 and 7 of theKashiwazaki-Kariwa plant, unit 5 of the Hamaoka
plant, and unit 2 of the Shika plant. These earlier
builds had been completed in a timely fashion andat costs that informed the original MIT study’s
conclusions that cost reductions were plausible(Deutch, Moniz, et al. 2003).11 The ABWR and the
ESBWR had both been selected as a design for one
or more prospective builds in the United States
when industry forecasts had many new builds onthe drawing boards, but none of those projects
advanced to the actual start of construction. To
date, construction of the ESBWR has not begun
anywhere in the world. The GE and Hitachi joint
venture had been in negotiations with a site
in India for the ESBWR, but so far nothing hasgone ahead.
The state-owned Korea Electric Power Company(KEPCO) developed the Gen-III+ Advanced Power
Reactor 1400 (APR1400), which builds on the
success of the construction program for its Gen-II
Optimum Power Reactor (OPR).
• The first APR1400, the Shin Kori plant’s Unit 3,
had been scheduled for completion in 2012, but
a string of problems with certifying importantpieces of equipment and other issues delayed
final completion until 2016. However, reliable
cost information is not available.
• KEPCO won the competitive bidding to provide
four reactors of this design to the United ArabEmirates at the Barakah site. The first of thefour units is nearing completion with minimal
delay, and the others are in process. The
reported price for the reactors is $3,457/kW,
although it is difficult to be sure what isincluded in this number. We include the figure
in Table H.1 because it is a very important data
point given KEPCO’s discipline in construction
and its competitive ability to win the Barakahtender. However, in Figure 2.3 we color thatdata point differently to signify uncertainty
about the number.12	Original dates from SCE&G’s application for certification of the units. Revised dates from the Wall Street Journal,
March 31, 2012.
10	Du and Parsons (2009) had estimated $3,800/kW based on partially redacted numbers in SCE&G’s 2008
submission to the Public Service Commission. However, subsequent filings show an even lower number. The latest
reported figures are based on a 2016 order. Both the original and the latest reported values are very low comparedto other projects.
11	Two other ABWR units began construction but were interrupted for non-economic reasons: at Lungmen, Taiwan
and Shimane, Japan.
12	KEPCO, December 2016, Investor Presentation, reports a total cost of $18.6 billion. Dividing this by the total
5,380 GW capacity of the 4 units yields the $3,457/kW figure. The presentation provides no detail about what isincluded in this figure or the quotation convention. For example, it probably excludes owners’ costs which could
add another 20% in order to be comparable to other figures. Press reports variously report the deal to be worth$20 billion, $25 billion, $30 billion, or even $40 billion. This latter figure is from the Korea Herald, June 20, 2015.
9

Measuring the Cost of Recent New Nuclear Power Plant Builds

223

• KEPCO filed an application to have the
APR1400 design certified with the U.S. NRC,
but the design has not yet been a candidate fora specific project in the United States.
The results for the U.S. and Western European
designs, regardless of where constructed, havebeen abysmal. We see cost overruns wherevergood cost data are available, and we see extensive
construction delays at most projects. This is
in contrast to the earlier history of disciplined
construction of the ABWR in Japan. As far as
demonstrations go, the cost of building certainof these new Gen-III+ designs has been muchhigher than originally estimated and projected.13 In
contrast, the recent APR1400 build in the United
Arab Emirates shows experience in keeping to thepromised construction schedule, and may show
the needed cost reductions, although the publicly
available data are not yet sufficient to say sowith confidence.
We must also take note of the other locations
for active construction of new Gen-III+ designs,
which are in Russia and China. Both countries
are pursuing a domestic construction programand exports. Neither makes available any reliable
cost data.

	In engineering it is common to distinguish between the cost of a first-of-a-kind (FOAK) plant, and the cost of an
nth-of-a-kind plant. The first build of a new design is likely to have extra costs. Many costly aspects of the build
process will shakeout with experience. The Gen III+ designs discussed above all included some FOAK plants. It canbe tempting to excuse some of the cost overruns on this basis, and to insist that the NOAK plants might have a
cost in-line with the original benchmark. In retrospect there is, by definition some truth to this: each of the vendors
and contractors is now re-examining the design and the construction process looking for improvements that canbe made to reduce the cost going forward. While there have been reduction in cost in Asian plants, this excuse
is at odds with the historical record of Western builds. It ignores the facts about particular estimates made at
the time. Take for example, the AP1000 reactors sold for the Vogtle and Summer sites. Estimated costs for thosebuilds were presented to the respective state public utility commissions in official filings. Those estimated costs
were represented as all inclusive, meaning that they incorporated any anticipated FOAK costs. Those official filings
were part of the basis informing the benchmark reported in the MIT 2009 Update.

13

224

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDREFERENCES
Deutch, J., C. Forsberg, A. Kadak, M. Kazimi, E. Moniz,
and J. Parsons. 2009. Update of the 2003 Future of
Nuclear Report. Massachusetts Institute of Technology,
Cambridge, Massachusetts: MIT.
Deutch, J., E. Moniz, S. Ansolabehere, M. Driscoll, P.
Gray, J. Holdren, P. Joskow, R. Lester, and N. Todreas.
2003. The Future of Nuclear Power. Massachusetts
Institute of Technology, Cambridge, Massachusetts:MIT.
Du, Y., and J. Parsons. 2009. “Update on the Costof Nuclear Power.” MIT Center for Energy andEnvironmental Policy Research Working Paper, 09-004.

Measuring the Cost of Recent New Nuclear Power Plant Builds

225

226

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix I

Influence of Country-Specific Labor Costs
on the ‘Overnight’ Cost to Construct
a Light Water Reactor
One of the chief obstacles to the deployment of large, Gen-III+ nuclear plants is theinherent inefficiency of fabricating, assembling, testing, and commissioning these large
and complex plants on site. While some advances have been achieved in construction
methods and fabrication techniques since the 1970s and 1980s, the delivery of a lightwater reactor (LWR) remains a very labor-intensive, hands-on effort requiring many years
to complete. Thousands of workers are deployed at the reactor site during construction,and total labor requirements correspond to 20–30 million person-hours for a gigawattscale LWR.
Given these large labor demands, regional orcountry-specific labor costs and labor productivity
were assumed to have a significant effect onovernight plant construction costs. This hypothesis
was based in part on the labor-rate data shownin Figure 2.4 of Chapter 2. However, these labor
rates are not specific to the nuclear industry. Thisappendix discusses an independent assessmentof nuclear-specific labor costs and the impact
of productivity for four reference countries: theUnited States, the Republic of Korea, France,
and China.
The evaluation was limited to the construction ofa pressurized water reactor (PWR) for simplicity
and was performed using the methodology
mapped out in Figure I.1.
The evaluation included the following
specific steps:
Definition of a Reference Plant – The first step inthe evaluation was to decide if the country-specificevaluations would be performed using a countryspecific reactor design (e.g., AP1000 for theUnited States and China; OPR1000 or APR1400

for Korea; EPR for France). Alternatively, we
could select a hypothetical single unit reference
design. Because of significant differences among
current LWR designs, we opted to use a common
reference design corresponding to a conventional
Gen-III LWR, with an electric generating capacityof 1,100 megawatts (MWe), as a more appropriate
baseline for assessing relative labor cost andproductivity effects. This approach had theadded advantage of being consistent with thereference design used in the Oak Ridge National
Laboratory (ORNL) Energy Economic Data Base(EEDB) evaluations from the 1980s, from which
the Code of Accounts (COAs) discussed below
were extracted.
Adoption of a Labor Cost Methodology –Various approaches for estimating laborcosts were considered including bottom-up
estimates and top-down estimates, where the
top-down estimates were generated by applying
multipliers to equipment costs to estimate labor
requirements (for construction, equipment
installation, and testing and commissioning),with added multipliers for home office costs,
engineering, quality assurance, and management.

Influence of Country-Specific Labor Costs on the ‘Overnight’ Cost to Construct a Light Water Reactor

227

Figure I.1: Overview of country-specific labor cost analysis (OH = overhead, G&A = general administrative
expense, OCC = overnight construction cost)This approach was judged to be too simplistic.
Instead, the Code of Accounts (COA) used by the
EEDB, which is similar to that developed by theinternational Generation IV Program, Economic
Modeling Working Group (EMWG), was used.

assessment model. For the analysis, eight generalcategories of labor similar to those in the model
were used, but a total of 28 labor rates werecompiled for each country. For example, craft laborcosts were developed for 11 separate job titles.

Estimation of Labor Hours Required by Activity/
Task/Account – Once the labor cost model wasdeveloped using the EEDB COAs, person-hour
estimates by discipline (craft, supervision,
management, QA, home office, etc.) weretaken from the EEDB reports, Electric Power
Research Institute (EPRI) reports, other sourcesof information (e.g., public disclosures for
projects such as Vogtle Units 3 and 4), and, toa lesser extent, estimates for overseas projects.
Eight categories of labor were used (structural;mechanical; electrical/I&C; construction
services, including carpenters; engineering;field supervision; quality; and “other,” suchas administration).

Labor Costs and Averaging/Extrapolation – Oncethe labor categories and job titles were defined,
the rates for each country were developed from:(a) published information; (b) interviews withutilities, nuclear steam supply systems designers
and large construction subcontractors actively
working at plant sites in the United States, France,
and Korea; and (c) other sources such as data
published by unions. Data for China were takenfrom published sources as well as from the China
Quote System for power plant construction as of2016. A stepwise change (increase) in Chineselabor rates for power plant construction wasreported to have occurred in 2016 but informationon this change was not available at the time of
the analysis. In those cases where a specific wage
was not available for a country, an extrapolation
was made.

Labor Categories and Job Title – We determined
early in the process that reported nuclear-specificsalaries/labor costs were not always consistent
with the eight categories used in the cost

228

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Estimation of Indirect Costs and Multipliers –Once the model was populated with labor costs,
total direct labor costs were calculated for thereference plant. Indirect costs such as overhead,general and administrative (G&A) expense, andfee were estimated on a country-specific basis
and then used to calculate the loaded costs.
These indirect multipliers ranged depending on the
country: a factor of 3 for Korea, 3.4 for the UnitedStates, 3.7 for France, and 5 for China.
Estimation of Country-Specific Productivity –Because it is expected that the number of hours
required to perform a specific task at the plant
construction site is directly proportional to worker
productivity, an adjustment could be made tolabor costs after the analysis. Alternatively, thisadjustment could be made earlier in the analysis
by scaling labor-hour requirements by task fora given country. With little quantitative data,no such changes were made here.

Calculation of Labor Costs for Reference Plant –As a last step, we calculated overall overnightlabor costs for the hypothetical 1,100-MWe plant.
Sensitivity studies were also completed toevaluate the effect of: (a) potential learning
curves (especially in countries such as Korea andChina), (b) number of workers on site (e.g., excess
workers on site for training purposes), and (c)potential labor cost reductions associated withmultiple-unit construction sites.
Overall, as shown in Figure 2.6 in Chapter 2, laborcosts accounted for 15%–35% of plant overnight
costs, depending on the country. Labor costs were
lowest in China and highest in the United States.
The labor cost difference between these twocountries was approximately $900/kWe relative
to an assumed (country-independent) averageovernight cost of $4,000/kWe. The results forFrance and Korea were similar, with differencesin labor costs accounting for about approximately$400/kWe.

Influence of Country-Specific Labor Costs on the ‘Overnight’ Cost to Construct a Light Water Reactor

229

230

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix J

Energy Storage
Energy storage technologies offer potential to enhance revenues from the operation of
baseload nuclear power plants because they make it possible to store energy when theprice of electricity is low, and sell that energy when demand—and price—are high. In
essence, energy storage opens up new peaking markets for nuclear beyond traditional
baseload operation.
We examined a broad range of energy storage
technologies (Forsberg 2017) including electricalstorage (capacitors and electromagnetic devices),mechanical storage (pumped hydro, compressed
air, and flywheels), batteries (including a rangeof static and flow types), and thermal storage(of both sensible heat and latent heat). A plot ofprojected storage costs, expressed in terms ofadded plant levelized cost of electricity (LCOE) at
the scale necessary for integration with a nuclear
reactor, is shown in Figure J.1.

The overall economics of energy storage
systems has not been extensively studied yet.
Furthermore, each storage technology has
different characteristics with respect to rate ofcharging, rate of discharge, roundtrip efficiency,
and readiness. As a consequence, the preferred
option will depend on the electricity market.

Figure J.1: Added nuclear power plant LCOE ($/MWh) for different energy storage options (The color of the bars
signifies the type of storage: green is mechanical, orange is thermal, and blue is electrical.)Sensible Heat
Compressed Air
Latent Heat
Pumped Hydro
Iron Air
Lead Acid
Polysulphide Br
Zinc Air
Vanadium Redox
Solid Oxide
Zinc Bromine
Nickel Zinc
Na-Ni Chloride
Alkaline
Sodium Sulphur
Nickel Metal…
Molten Carbonate
Lithium Ion
Flywheel
Nickel Cadmium
0

2

4

6

8

10

12

14

16

18

Added Plant LCOE [$/MWh]

Energy Storage

231

The methods used to value storage technologies
are not always well established nor are they
always applied consistently. Typically, the cost ofsuch systems is given by the following equation:
E · μEC = ηRT + P • μP
Where
C = the capital cost [$];
E = the desired capacity [kWh];μE = the capacity cost [$/kWh];ηRT = the roundtrip efficiency, which captures themarginal energy losses induced by adding
the storage cycle (typically expressed as theratio of energy immediately out of the device
to energy in);
P is the desired power [kW]; andμP is the power cost [$/kW].
The analysis used to generate the results shownin Figure J.1 assumes 1 gigawatt hour (GWh) of
storage and 100 megawatts (MW) of discharge
power based on Westinghouse estimates fora pressurized water reactor (PWR) retrofit. By
contrast, the analysis in Chapter 1 assumes
battery storage with 2 megawatt hours (MWh)of energy storage capacity and 1 MW of charging
or discharging power in the GenX simulations.
Furthermore, the analysis here is based on current
costs whereas the discussion in Chapter 1 uses
projected costs in 2050 to account for potential
reductions in the cost of storage technologies overthe next three decades.

232

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

For a more accurate comparison between energy
technologies, it is best to calculate the total
capital cost of the energy storage system using
the formula given above and then convert thiscapital cost into an estimate of ‘added LCOE’ forthe specific storage technology being considered.
It should be noted that the cost of a given energy
storage technology could be different when
paired with other energy generation technologies
because of different scale and storage
capacity needs.

REFERENCES
Forsberg, C. 2017. Light Water Reactor Heat Storage forPeak Power and Increased Revenue: Focused Workshop on
Near-Term Options. Cambridge, Massachusetts.

Energy Storage

233

234

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix K

Economic Calculations for Advanced
Nuclear Energy Concepts
This appendix discusses the basics of estimating power plant costs and provides a simple
example, using a light water reactor (LWR), for the reader. Then, we apply the equations
used in this example to estimate costs for advanced reactors and compare the economics
of different advanced power conversion systems.

BASICS OF COMPONENTS
OF POWER PLANT COST
There are three basic components to the costof a plant that produces electricity (or any otherenergy product):• Capital Cost—This is the largest cost
component; it comes from the cost of building
the plant and is composed of two parts. The‘overnight cost’ of the plant is the cost tobuild it including the equipment, construction
materials, and labor. The second part of capital
cost is the cost of the interest that must be
repaid for borrowing the money to construct
the plant. Interest costs are affected by theconstruction time and the interest rate thatapplies to the borrowed money, which is
known as ‘interest during construction’ (IDC)or ‘accumulated funds during construction’(AFDC).

• Operating and Maintenance Cost—This
cost component is the cost of operating andmaintaining the power plant; it depends in parton the staffing needs associated with runningthe plant.
• Fuel Cost—This is the cost of the fuel used to
produce the electricity.
Capital costs (including overnight construction
cost and interest costs) can be considered fixed
costs that are incurred whether the plant produces
electricity or not. Operating costs have a variable
portion. The fuel cost is only incurred when theplant is operating. Capital cost typically makes up
more than 80% of the cost of a nuclear plant; theremainder of the cost is divided typically between
the operating cost (15%) and the fuel cost (5%).

Economic Calculations for Advanced Nuclear Energy Concepts

235

The levelized cost of electricity (LCOE) is thengiven by:
LCOE =

=1000
8766*L

[



]
()

I
O
+
+ FCC
K
K

(A/P,,N)–(1 – )(1 – )1N

where,LCOE = levelized cost of electricity, mills/kWhe;1
K = power plant size [kWe];
L = annual capacity factor[actual kWhe/rated kWhe];I = capital cost of the power plant including
AFDC or IDC [$];
O = annual operating & maintenance cost [$/yr]; = levelized fixed charge rate [yr-1], accounting
for both taxes and depreciation;
N = assumed plant economic life [years]; = discount rate { = fsrs + fbrb (1 – )};fs = fraction debt;
fb = fraction equity;
rb = rate on debt (bonds) (%);
rs = rate on equity (stock) (%);
 = composite tax rate;
1/N = straight-line depreciation fraction;(A/P,,N) = Capital Recovery Factor =[(1 + )N]/[(1+)N – 1];
FCC = fuel cycle cost;and 8,766 is the number of hours in a year.
The nuclear fuel cycle cost is given by:
FCC = 1000*Cf /(24B)
where:
Cf = total [net] fuel cycle cost [$/kg], including
enrichment, conversion, fabricationand disposal;
B = fuel burnup at discharge[MWDth/MTU] [megawatt-days-thermal/
metric-ton-uranium]; and = plant thermal efficiency [kWe/kWth].

SIMPLE LIGHT WATER REACTOR(LWR) CASE
As a simple example, we consider an idealized
AP1000 reactor assuming the cost inputs listed
below:
FactorValue

L= capacity factor [actual kWhe/rated kWhe]0.85

 = annual fixed charge rate, yr-1

0.10

I/K= specific capital cost, $/kWe

5000

K = Plant capacity, MWe

1100

O/K= annual operating cost, $/yr-kWe

70

Cf = total [net] fuel cycle cost, $/kg

2500

B = fuel burnup at discharge MWDth/MTU

50,000 = plant thermal efficiency, kWe/kWth0.33

N = assumed plant economical life (years)

30

We would then calculate that the LCOE =67.1 + 9.4 + 6.3 ~ 82.8 mills/kWhe (or $/MWhe),which is very similar to the value of 83.5 mills/
kWhe calculated under similar assumptions by the
U.S. Energy Information Administration (EIA) in its
2015 Annual Energy Outlook.

Advanced Reactor Cost Estimates
Advanced reactor costs are more difficult toestimate because of the lack of design detailand historical basis for construction of thesesystems, and because different sources use
varying assumptions about key cost components.
Open sources for overnight capital cost estimates
were used to establish the costs presented inTable K.1. They are compared to cost estimatesfor U.S. pressurized water reactors (PWRs) fromthe Energy Economic Data Base (EEDB) (United
Engineers and Constructors 1986) both for thebest plant, as described by Ganda, et al. (2016),
and for the median plant, as described by Lucid
Strategies (2018). Costs listed in these sources foreach labor component and materials are escalated
to current dollars. (Values are rounded to thenearest dollar in this appendix, but to the nearest
hundred dollars in the main text.)	A ‘mill’ is equal to one-tenth of one cent, or $0.001. Note that 1 mill/kW (or 1 mill/kWh) is equal to $1/MW(or $1/MWh).

1

236

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Table K.1: Comparison of cost estimates for different reactor types
Comparison of Reactor Cost Estimates ($/kWe) for Different Reactor Types

Cost Categories

Unit/Size

PWR MedianExperiencefrom Lucid
Strategies

1

PWR 1100 MWe
Best Experiencefrom 1988 to2014 using
ANL escalation
approach

HTGR 2400
MWth/1000
MWe (2009)(from INL)

1100 MWe
SFR/ANL(2014) fromANL

1 4x600 MWth 4x840 MWth

AHTR 3400
MWth/1350 MWe
12x242 MWth(2011) based on
FHR with NACC
1100 MWe PWR(142 MW) fromw using ANL
UCB thesis
Escalation basis for
PWR 1100 MWe

ORNL 1000 MWe MSR
Scaled to 2014 Basedon PWR Scaling of Lucid
Strategies but indirect
costs similar to otheradvanced reactors

1 12x242 MWth

1

91

Pre-Construction Costs
Structures and Improvements

574

476

331

470

412

659

Reactor Plant Equipment

694

719

1083

1254

719

870

Turbine Plant Equipment

487

531

478

418

Electrical Plant Equipment

217

193

Miscellaneous Plant Equipment

126

111

Main Cond Heat Reject System

103

116

157
473

209

101

440
266
159
61

220

Special Materials
TOTAL DIRECT COST

Detailed
381 breakdown as
154 shown here is
not provided
97

2201

2146

2456

2508

2085

2316

2455

1669

273

Owner’s Cost
Construction Services

739

538

494

Home Office Engin & Service

895

505

381

Field Office Engin & Service

819

263

231

TOTAL INDIRECT COST

2453

1306

1379

1609

1436

1343

Indirect Costs as % of Direct

111%

61%

56%

64%

69%

58%

68%

TOTAL BASE COST

4654

3452

3835

4117

3520

3659

4125

Contingency

10%

20%

20%

30%

30%

30%

Contingency

345

767

823.4

1056

1098

1237

3797

4602

4940

4576

4757

5362
20%

TOTAL OVERNIGHT COST

4654

355
1254

270
467
698

84%

20%

20%

20%

20%

IDC

1500

3189

644

692

641

666

751

TOTAL

6154

6986

5246

5632

5217

5423

6113

IDC Rate

Our cost estimates are based on traditional‘stick-built’ construction in the United States for an‘nth-of-a-kind’ (NOAK) plant. The NOAK plant is
identical to the first-of-a-kind plant supplied andbuilt by the same vendors and contractors with
only the site-specific scope altered to meet the
NOAK plant site’s needs. Costs for NOAK plants
are achieved only after many such reactors havebeen constructed for a particular nuclear systemdesign.
Cost estimates for a high-temperature gas-cooled
reactor (HTGR) (Gandrik 2012) and sodiumcooled fast reactor (SFR) (Ganda 2015) are themost current estimates openly available. They arebased on conceptual designs. Cost estimates forthe fluoride-salt-cooled high-temperature reactor(FHR) (large and small) and molten salt reactor(MSR) are based on pre-conceptual designs.
Indirect costs for the small FHR (Andreades 2015)
are based on those assumed for the HTGR. Costs
for the large FHR (Holcomb 2011) were escalated
to current costs based on the work of Ganda, et al.
(2016). Costs for the MSR (Engle 1980) are basedon early-1980s vintage pre-conceptual designs
and were escalated using LWR direct costs from
Lucid Strategies; to allow for a fair comparison,
however, we used the large FHR indirect cost
percentage for consistency. The scaling factors
used to escalate costs are found in Table K.2.
Overnight costs include capital costs, indirect
costs, and a contingency factor, as discussed
below.

Economic Calculations for Advanced Nuclear Energy Concepts

237

Table K.2: Scaling factors used to escalate costsin the analysis
Scaling for
AHTR basedon escalation
approach by
Ganda

Indirect Costs

Scaling for
MSR basedon Lucid
Strategies

Pre-Construction Costs
Structures and Improvements

1.24

5.23

Reactor Plant Equipment

1.19

4.84

Turbine Plant Equipment

1.19

4.40

Electrical Plant Equipment

1.21

4.93

Miscellaneous Plant Equipment

1.21

Main Cond Heat Reject System

1.21

4.32

Special Materials
TOTAL DIRECT COST
Owner’s Cost
Construction Services

1.19

Home Office Engin & Service

1.19

Field Office Engin & Service

1.19

TOTAL INDIRECT COST

Capital Costs
Capital costs in Table K.1 were obtained fromestimates developed by the teams working on
different advanced reactor designs. These costs
were binned into the traditional code of accounts
for reactor systems:• Pre-construction costs• Structures and improvements (site preparation,
excavation etc.)• Reactor plant equipment (cost of the nuclear
steam supply system or NSSS)• Turbine plant equipment (cost of theturbine island)• Electrical plant equipment• Miscellaneous plant equipment• Main condenser heat rejection system• Special materials (for example, molten
salt, which, depending on the salt, can bevery expensive)238

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

Given limited experience in the constructionof advanced reactor systems, indirect costs(installation, home and field engineering, andconstruction services) are expressed as apercentage of direct costs. Indirect costs include
the following sub-categories:• Construction services – including but notlimited to costs for construction management,
procurement, scheduling, cost control, site
safety, and quality inspections.
• Home office and engineering services –including but not limited to costs for estimating,scheduling, project expediting, projectgeneral management, design allowance, andproject fees.
• Field office and engineering services –including but not limited to costs for the field
office, field engineering, field drafting, fieldprocurement, and field administrative andgeneral expenses.
• Owner’s costs – including but not limited toproject fees, taxes, and insurance; spare partsand other capital expenses; staff training andstartup costs; and administrative and general
expenses, but not interest during construction.
• Design costs – preconstruction engineering,
design, and layout work associated withthe site.
An indirect cost multiplier of 57% was used for the
HTGR and 64% for the SFR. (No escalation was
done for these two cost estimates.) Indirect costs
are collectively a large part of the overall cost.
Estimates of actual indirect costs as a percentage
of direct costs from the historical LWR fleet spana large range. Some have been as low as 20%,
but a best practices value from the LWR fleet isabout 40% whereas the fleet average is 50%.
The U.S. Department of Energy’s cost estimation
methodology (1980) (1988) recommends 51%
based on reactors built prior to Three Mile Islandand 77% for reactors built after Three Mile Island.
The International Atomic Energy Agency (IAEA)

(International Atomic Energy Agency 1978)
recommends a value of 52%. Thus, the values
used here are considered reasonable.

Contingency
We provide a variable contingency for theseestimates to reflect cost uncertainty. The
contingency is based on the maturity of thedesigns, associated technology development, andsupply chain considerations. Mature conceptual
designs approaching the level of preliminary
design (HTGR and SFR) were thus assigned a 20%
contingency, while early conceptual designs wereassigned a 30% contingency to reflect the lower
level of technical detail in these designs. Whilesome may consider these percentages to be low,
they are reasonable for comparison purposes.

Financing Costs
All systems were assumed to have construction
times of 60 months. We assumed 50% debt/50%
equity (6% debt and 12% equity), and a tax rateof 38%. This yields a discount rate, x, of 0.0786,
a capital recovery factor of 0.088, and a levelized
fixed charge rate, , of 0.121, which are used in allof the calculations presented here. The discountrate of 7.86% was used to calculate interest during
construction (IDC) as a multiplier of the overnight
capital cost using the formula:
IDC (also known as AFDC) = (1+N*x/2)

Overnight Costs and Total Capital
Investment
The overnight costs in Table K.1 are all very
similar: between $4,600/kWe and $5,400/
kWe. This is essentially the same value given theuncertainties involved, as discussed in Chapter 3.
For comparison, the overnight cost for NuScale,a small LWR, is projected to be approximately$5,000/kWe. Adding in interest cost during
construction results in a total capital investmentof between $5,200/kWe and $6,100/kWe. Shorter
construction times can reduce the total capital
investment shown here.

Estimates of the Levelized Cost of Electricity
Table K.3 shows capital cost, operating andmaintenance costs, and fuel cycle costs for several
advanced reactor concepts following the LCOE
equation given earlier. Direct costs were takenfrom Table K.1. Annual capacity factors wereassumed to be 0.9 for all reactor types.
Operating costs for the advanced concepts were
either provided in total dollars (and then converted
to $/kWe by dividing by the thermal power andcapacity factor) or were provided directly by theadvanced reactor team.
For the FHR with the air Brayton combined cycle,
the estimates assume operation with natural gas
50% of the time. This mode of operation boosts
the thermal power for an individual unit operating
at 100 MWth and 53% efficiency in reactor-onlymode to 242 MWth and 70% efficiency in thereactor and natural gas firing mode. The estimatesalso include the cost of natural gas associatedwith the air Brayton cycle, which is assumed to be$3.37/MWhe or only about 10% of O&M costs.
Higher O&M costs for this design are driven bylarge staffing needs at each of the individual units.
Fuel costs for HTGR (TRISO fuel) and SFR(metallic fuel) reactors are significantly larger thanfuel costs for current LWRs, in part because theseadvanced reactor fuels require higher levels ofenrichment but also because they involve different
fabrication methods. Neither design has been
deployed yet on large scale so fuel fabrication
cost reductions might be possible in the future.
Additional details were not available for SFR fuelcosts. HTGR fuel costs were based on enrichment
and fabrication costs and the anticipateddischarge burnup for the design. For FHR designs,
original cost assumptions for both small and large
systems that use TRISO fuel were underestimatedand were corrected based on the HTGR costestimate, which comes from vendor quotations.
For MSRs, a detailed estimate was not available,
but a nominal value was used based on the level ofuranium enrichment provided for this system.

Economic Calculations for Advanced Nuclear Energy Concepts

239

Table K.3: Details of LCOE calculations
Levelized Cost of Electricity Estimates
HTGR 2400
1100 MWe
MWth/1000 MWe SFR/ANL (2014)(2009) (from INL)
from ANL
Plant size (MWth)
Plant size (kWe)K

Annual capacity factor

L

Total Direct Cost $ORNL 1000 MWe MSR
12x242 MWth FHR
Scaled to 2014 Basedwith NACC (142on PWR Scaling of Lucid
MW) from UCB Strategies but indirect costs
thesissimilar to other advanced
reactors

2400

4108

3000

2904

2275

1.01E+06

1.51E+06

1.35E+06

1.33E+06

1.00E+06

0.9

0.9

0.9

0.9

0.9

2.46E+09

3.79E+09

2.81E+09

3.08E+09

2.46E+09

Indirect Multiplier

1.58E+00

1.64E+00

1.69E+00

1.58E+00

1.68E+00

Contingency

1.20E+00

1.20E+00

1.30E+00

1.30E+00

1.30E+00

IDC
Capital Cost including AFDCI

OVERNIGHT COST
(does not include IDC)

1.20E+00

1.20E+00

1.20E+00

1.20E+00

1.20E+00

5.57E+09

8.92E+09

7.40E+09

7.57E+09

6.42E+094619.624947.424579.524748.035356.36
0.121

Levelized fixed charge rate

phi

0.121

0.121

0.121

0.121

Economic Plant life

N

30

30

30

30

30

Tax rate

tau

0.380

0.380

0.380

0.380

0.380

Discount ratex

Capital recovery factor

0.079

0.079

0.079

0.079

0.079

0.088

0.088

0.088

0.088

0.088

Conversion factor (1000/8766*L)

0.127

0.127

0.127

0.127

0.127

SPECIFIC CAPITAL COST (I*phi/K)(mills/kWehr)

84.74

90.75

84.00

87.10

98.25

9.96E+07

1.03E+08

3.12E+08

98.81

76.13

233.79Annual O&M costO

Annual O&M cost ($/kW)
SPECIFIC O&M(O/K) (mills/kWehr)

12.52

8.34

9.65

33.00

12

Fuel Cycle cost

$/kg

22373

Burnup

MWD/MTU

132000

Plant efficiency

kWe/kWth

0.42

0.37

0.45

0.46

16.81

14

17.54

14.98

9

114.08113.10111.19135.08119.25

Fuel Cycle Cost (mills/kWehr)TOTAL LCOE

mills/kWehr

Operational costs range between 8 and 13 mills/
kWhe (or $/MWhe) except for the small FHR,
which is a 12-module plant for which costs were
derived by scaling from the HTGR. Had a common
cost for O&M been used, all of the systems would
have an LCOE of approximately $110–$120/MWhe.
These values are slightly greater than the values
for advanced LWRs provided by the U.S. Energy
Information Administration (2016) ($92–$100/
MWhe) and NuScale estimates (Surina 2016)($96–$106/MWhe). Lower interest rates andshorter construction times can reduce the LCOE
values presented here.

240

AHTR 3400
MWth/1350 MWe(2011) based on 1100
MWe PWR using ANL
Escalation basis for
PWR 1100 MWe

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

16500
1000000.44

Comparison of Advanced Power Conversion
Options
As part of our assessment of crosscutting
technologies, we evaluated advanced power
conversion systems to determine if an increase inthermal efficiency improves the overall economicsof the plant for two cases:• An HTGR at 950°C with a helium Brayton cycle
compared to the conventional HTGR at 750°C
with a superheated Rankine cycle.
• An SFR with a supercritical CO2 cycle compared
to a conventional SFR with a Rankine cycle.

Because of the increase in thermal efficiency,
all cost components of the LCOE are affected in
the calculation.
For the HTGR independent bottom-up costestimates were developed for each option from
Gandrik (2012). As shown in the Table K.4,
the helium Brayton cycle and the higher outlet
temperature increase the efficiency of the systemfrom 42% to 50% but these design choices also
increase the capital cost. Comparing the two cases
indicates very similar LCOEs for these two reactor
designs.
For the SFR, the use of supercritical CO2 increases
the efficiency from 37% to 50%. However, adetailed assessment of the design that integrates
the supercritical CO2 cycle was not available.

Instead, we performed a top-down type of analysis
and increased the capital cost until the LCOEs areequal, which corresponds to an additional$825/kWe. Because a traditional Rankine cycle
costs about $500/kWe (McKellar 2010)(Ho, et al. 2015), the supercritical option with thechange in heat exchanger breaks even with theconventional system at a cost of approximately$1,325/kWe. Cost projections for the nth-of-a-kindsupercritical CO2 cycle are in the same range:
between $1,000/kWe and $1,200/kWe(Ho, et al. 2015).
Thus, despite gains in efficiency, these advanced
power conversion cycles do not change the overall
economics significantly.

Table K.4: Comparison of HTGR and SFR LCOEs with different power conversion cycles
HTGR 2400 MWth/1000
MWe (2009) (from INL)
Plant size (MWth)
Plant size (kWe)K

Annual capacity factor

L

TOTAL DIRECT COST $HTGR 4x600 pack
950 C Brayton(from INL)

1100 MWe
SFR/ANL (2014)
from ANL

1000 MWe SFR with SCO2
(assuming $825/kWe extra
for SCO2 changes)

2400

2400

4108

4108

1.01E+06

1.20E+06

1.51E+06

2.05E+06

0.9

0.9

0.9

0.9

2.46E+09

3.28E+09

3.79E+09

5.48E+09

Indirect Multiplier

1.58E+00

1.58E+00

1.64E+00

1.64E+00

Contingency

1.20E+00

1.20E+00

1.20E+00

1.20E+00

IDC
Capital Cost included AFDCI

OVERNIGHT COST
(does not include IDC)

1.20E+00

1.20E+00

1.20E+00

1.20E+00

5.57E+09

7.44E+09

8.92E+09

1.29E+104619.625192.794947.425252.04
0.121

Levelized fixed charge rate

phi

0.121

0.121

0.121

Economic Plant life

N

30

30

30

30

Tax rate

tau

0.380

0.380

0.380

0.380

Discount rate

x

0.079

0.07860.079

0.0786

Capital recovery factor

0.088

0.088

0.088

0.088

Conversion factor (1000/8766*L)

0.127

0.127

0.127

0.127

SPECIFIC CAPITAL COST
(I*phi/K) (mills/kWhr)

84.74

95.25

90.75

96.34

9.96E+07

9.96E+07

98.81

83.17
8.34

6.12

Annual O&M costO

Annual O&M cost ($/kW)
SPECIFIC O&M(O/K) (mills/kWhr)

12.52

10.54

Fuel Cycle cost

$/kg

22373

22373

Burnup

MWD/MTU

132000132000

Plant efficiency

kWe/kWth

0.42

0.499

0.37

0.5

16.81

14.15

14

10.248114.08119.95113.10112.71

Fuel Cycle Cost (mills/kWhr)TOTAL LCOE

mills/kWhr

Economic Calculations for Advanced Nuclear Energy Concepts

241

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Andreades, C. 2015. Nuclear Air Brayton Combined Cycle
Power Conversion Design, Physical Performance Estimationand Economic Assessment. Thesis, UC Berkeley.
Engle, J. 1980. “Conceptual Design Characteristics ofa Denatured Molten-Salt Reactor with Once-throughFueling.” ORNL/TM-7207, Oak Ridge National
Laboratory.
Ganda, F. 2015. “Economics of Promising Options.
Prepared for the U.S. Department of Energy Fuel Cycle
Options Campaign.” FCRD-FCO-2015-000013, Argonne
National Laboratory.
Ganda, F., J. Hansen, T. Kim, T. Taiwo, and R. Wigeland.
2016. “Reactor Capital Costs Breakdown and Statistical
Analysis of Historical US Construction Costs.”
International Congress on Advances in Nuclear Power
Plants, ICAPP 2016.
Gandrik, A. M. 2012. Assessment of High Temperature
Gas-Cooled Reactor (HTGR) Capital and Operating Costs.
TEV-1196, Idaho National Laboratory, Idaho National
Laboratory.
Ho, C., M. Carlson, P. Garg, and P. Kumar. 2015. “Costand Performance Tradeoffs of Alternative Solar-Driven
S-CO2 Brayton Cycle Configurations.” ASME 9thInternational Conference on Energy Sustainability.
San Diego, CA.
Holcomb, D. 2011. Advanced High Temperature Reactor
Systems and Economic Analysis. ORNL/TM-2011/364,
Oak Ridge National Laboratory, Oak Ridge National
Laboratory.
International Atomic Energy Agency. 1978. “Capital
Investment Costs of Nuclear Power Plants.” IAEA
Bulletins 20 (1): 11-23.
Lucid Strategies. 2018. The ETI Nuclear Cost Drivers
Project: Summary Report.
McKellar, M. 2010. Power Cycles for the Generation ofElectricity form a Next Generation Nuclear Plant. TEV-674,
Idaho National Laboratory.
Surina, J. 2016. “NuScale Power Plant Economics.”
Presentation.
United Engineers and Constructors. 1986. Phase VIM
Update (1986) Report for the Energy Economic Data Base
Program. DOE/NE-0079, U.S. Department of Energy.
U.S. Department of Energy. 1980. “Power Plant Capital
Investment Cost Estimates: Current Trends andSensitivity to Economic Parameters.” DOE/NE-009.
U.S. Department of Energy. 1988. “Nuclear Energy Cost
Data Base.” DOE/NE-0095.
U.S. Energy Information Administration. 2016. Levelized
Cost and Levelized Avoided Cost of New Generation
Resources in the Annual Energy Outlook 2015. U.S.
Department of Energy.

242

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAppendix L

Delivering Nuclear Megaprojects On Time
and On Budget: Challenges and a Potential
Solution
Megaprojects are defined as projects with large budgets (above $1 billion) and a high levelof complexity. Typical gigawatt-scale nuclear power plant construction projects fit thisdefinition. Megaprojects present substantial technical and financial risks and are often
implemented after a sub-optimal planning phase that underestimates their costs andoverestimates their short-term benefits (Flyvbjerg 2006).
An analysis of data from 318 industrial
megaprojects shows that most may be considereda failure from the point of view of meetingschedule and budget targets and deliveringpromised benefits in operation (Merrow 2011).
Cantarelli, et al. (2010) summarize the likely
causes of this poor performance record:• Technical challenges—These can include
forecasting errors with regard to the priceescalation of materials, or incomplete estimatesof cost and uncertainty, changes in project
scope, and inadequate organizational structure.
• Psychological factors—The well-documented
tendency of project proponents, including
project executives and officials, to display
optimism bias in their assessments of costand performance.
• Commercial incentives—The tendency
of vendors/contractors to intentionally
underestimate cost and overestimate benefit inorder to ‘sell’ a project.
• Political factors—The manipulation of costand benefit forecasts by decisionmakers forunethical reasons, for example, to gain support
in upcoming elections or obtain a personal
benefit (see also Locatelli, et al. 2017).

• Organizational challenges—These can arise
when a project (or major subcontract) isawarded to the lowest “turn-key” bid without
proper consideration of the contractor’s ability
to manage project risks.
Merrow (2011) submits that the most common
causes of budget overruns and delays inmegaprojects are stakeholders’ greed; pressure
to reduce estimates of construction time andincrease the expected net present value of the
project; an ineffective bidding phase; pressure to
reduce upfront costs, which leads to poor quality‘front end loading’ (FEL) and ‘front end engineeringand design’ (FEED); unrealistic cost estimates; andineffective risk allocation among project partners.
Several empirical studies (Ansar 2014) (Sovacool,
Gilbert and Nugent 2014) have shown thatthe larger the megaproject, the greater the
likelihood that it will experience cost overruns
and delays. Locatelli, Mancini and Romano (2014)
investigated the role of complexity (technical andorganizational) in megaprojects and found that
underperforming projects are often delivered in anenvironment characterized by interoperable andinterdependent systems; emphasis on reducing
costs and tightening schedules without the
reductions in project scope needed to make these

Delivering Nuclear Megaprojects On Time and On Budget: Challenges and a Potential Solution

243cost and time parameters feasible; integration
issues (i.e., high number of system parts andhigh number of organizations involved, often
from multiple technical disciplines); competitive
pressure from other technologies within the same
market (e.g., natural gas or renewable generatorsin the case of nuclear power plants) or fromalternative systems using the same technology(e.g., different nuclear reactor designs).
The nuclear energy industry in Western Europe
and the United States has experienced chronic
problems with budget overruns and schedule
delays in power plant construction projects—infact, these issues seem to be systemic and there
has been no apparent improvement over time. Thishas fostered ‘tolerance for deviation’ (Pinto 2014)—
that is, when members of a business community
become so accustomed to a deviant behavior thatthey do not consider it to be deviant anymore.
Decisionmakers play the necessary ‘politicalgames’ to ensure support for a project despite apoor record of project management (Pinto andPatanakul 2015) but ultimately consistent poor
performance is not sustainable. The Korean
nuclear program is one of few exceptions to thegeneral trend. The standard Korean 1-gigawatt
power plant design has been consistently built
on budget and within a reasonable schedule (fiveto six years), and the existing fleet of Korean
reactors has had good operational performance.
The Koreans established a ‘supply chain for
construction’ to deliver a series of plants based on
replicating a standardized reactor design rather
than building individually-designed plants. In
megaprojects, especially in the nuclear energy
industry, a key strategy for achieving good
performance (where performance is measured byadherence to budget and schedule), appears to be
standardization—both of the project supply chain(i.e., the same stakeholders involved in delivering a
project that is replicable multiple times) and of the
product or project deliverable itself (in this case,the same power plant design duplicated over andover again) (Choi 2009). Small modular reactors(SMRs) naturally lend themselves to both supply

244

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD

chain and product standardization, thus one of thepotential advantages of this technology is that it
could improve project management performancein the nuclear sector. SMRs face a number of
deployment challenges, from licensing to maturityof the supply chain to financing of early projects(Sainati, Locatelli, and Brookes 2015), however the
potential rewards are great.

REFERENCES
Ansar, A., et al. 2014. “Should we build more large
dams? The actual costs of hydropower megaproject
development.” Energy Policy 69: 43–56.
Cantarelli, C. C., et al. 2010. “Cost overruns inlarge-scale transportation infrastructure projects:
Explanations and their theoretical embeddedness.”
European Journal of Transport and Infrastructure Research
10(1): 5–18.
Choi, S., et al. 2009. “Fourteen lessons learned from thesuccessful nuclear power program of the Republic ofKorea.” Energy Policy 37(12) : 5494–5508.
Flyvbjerg, B. 2006. “From Nobel Prize to project
management: Getting risks right.” Project Management
Journal 37(3): 5–15.
Locatelli, G., et al. 2017. “Corruption in public projects
and megaprojects: There is an elephant in the room!”
International Journal of Project Management 35(3):252–268.
Locatelli, G., M. Mancini, and E. Romano. 2014.
“Systems Engineering to improve the governance incomplex project environment.” International Journal of
Project Management 32(8): 1395–1410.
Merrow, E. W. 2011. Industrial Megaprojects: Concepts,
Strategies and Practices for Success. John Wiley & Sons.
Pinto, J. K. 2014. “Project management, governance, andthe normalization of deviance.” International Journal of
Project Management 32(3): 376–387.
Pinto, J. K., and P. Patanakul. 2015. “When narcissism
drives project champions: A review and research
agenda.” International Journal of Project Management33(5): 1180–1190.
Sainati, T., G. Locatelli, and N. Brookes. 2015. “Small
Modular Reactors: Licensing constraints and the way
forward.” Energy doi: 10.1016/j.energy.2014.12.079:
1092–1095.
Sovacool, B. K., A. Gilbert, and D. Nugent. 2014. “Aninternational comparative assessment of construction
cost overruns for electricity infrastructure.” Energy
Research & Social Science 3: 152–160.

Delivering Nuclear Megaprojects On Time and On Budget: Challenges and a Potential Solution

245

246

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLDAbbreviations and Technical Terms
ABWR

advanced boiling water reactor

EPRI

Electric Power Research InstituteACalternating current

ERCOT

Electric Reliability Council of Texas

EROEI

energy return on energy invested

ACRS	Advisory Committee on
Reactor Safeguards
ACI

American Concrete Institute

ESBWR	economic simplified boiling-water
reactorAEA

Atomic Energy Act

ESP

early site permit

AEC

Atomic Energy Commission

FAA

Federal Aviation Administration

AFDC

accumulated funds during construction

FDA

Food and Drug Administration

FEED

front end engineering and design

FHR

fluoride high temperature reactor

AP1000	Westinghouse pressurized water
reactor with improved use of passive
nuclear safety
APR1400	Korean advanced pressurizedwater reactor
ARC	an advanced sodium fast
reactor concept
ASLB

Atomic Safety and Licensing Board

ASME	American Society of
Mechanical Engineers

FLiBe	molten salt containing lithium fluoride
and beryllium fluoride
FOAK

first-of-a-kindGDAgeneric design assessment

GE

General Electric

GFR

gas-cooled fast reactor

GHG

greenhouse gas

BWRboiling water reactor

GT-MHR gas turbine modular helium reactor

CCGT

combined cycle gas turbine

HALEU

high-assay low-enriched uranium

CCS

carbon capture and sequestration

HTGR

high temperature gas-cooled reactor

CFR

Code of Federal Regulations

HTSE

high temperature steam electrolysis

CNS

Convention on Nuclear Safety

I&C

instrumentation and control

CO2carbon dioxide

IAEA

International Atomic Energy Agency

COL

combined operating license

IDC

interest during construction

COLA

combined operating license application

IEEE	Institute of Electrical andElectronics Engineers

COP21	21st yearly session of the Conferenceof Parties

IEO

International Energy Outlook

CPconstruction permit

IGCC

integrated gasification combined cycleDC

design certification

INL

Idaho National Laboratory

DOE

U.S. Department of Energy

INPO

Institute for Nuclear Power Operations

EEDB

Energy Economic Data Base

EIA

U.S. Energy Information Administration

ITAAC	inspections, tests, analyses andacceptance criteria

EPA

U.S. Environmental Protection Agency

KEPCO

Korea Electric Power Corporation

EPC	Engineering, Procurement
and Construction

LCOE

levelized cost of electricity

LFR

lead fast reactor

EPR

LNT

linear no threshold hypothesis

evolutionary power reactor

﻿

247

248

LWR

light water reactor

Units

MSR

molten salt reactor

Btu	British Thermal Unit

NAICS	North American Industry
Classification System°Cdegrees Celsius°F

degrees Fahrenheit

NOAK

nth-of-a-kind

g

gram

NGNP

Next Generation Nuclear Plant

GW

gigawatt (106 kW)

NNSA

National Nuclear Safety Administration

GWh

gigawatt-hour

NRC

U.S. Nuclear Regulatory Commission

J

Joule

NSSS

nuclear steam supply systemkgkilogram

O&M

operations and maintenancekm

kilometerkWkilowatt

OCGT

open cycle gas turbinekWhkilowatt-hourODSoxide dispersion strengthened

MMBtu	million British Thermal Unit

OECD	Organisation for Economic
Cooperation and Development

MT

metric ton

MWmegawatt (103 kW)

OL

operating license

MWhmegawatt-hour

ONR

Office of Nuclear RegulationTWhterawatt-hour (109 kWh)ORNL

Oak Ridge National Laboratory

PRA

probabilistic risk assessment

PRISM

Power Reactor Inherently Safe ModulePVphotovoltaic

PWR

pressurized water reactor

RAI

request for additional information

SDA

standard design approval

SFR

sodium fast reactor

SMR

small modular reactor

SPC

steel plate composite

SSC

system, structure or component

SWU

separative work unit

T-B-T

Tianjin, Beijing, and Tangshan

TRISO

tri-structural isotropic

U

Uranium

UHPC

ultra-high performance concrete

VHTR

very high temperature reactor

WNA

World Nuclear Association

THE FUTURE OF NUCLEAR ENERGY IN A CARBON-CONSTRAINED WORLD