Lessons from History, the Media, and Interviews · The Evergreen State College Archives Digital Collections

THE RENEWED INTEREST IN NEW NUCLEAR CONSTRUCTION
IN THE UNITED STATES:
LESSONS FROM HISTORY, THE MEDIA, AND INTERVIEWS

by
Kathleen M. Saul

A Thesis
Submitted in partial fulfillment
of the requirements for the degree
Master of Environmental Studies
The Evergreen State College
December 2009

This Thesis for the Master of Environmental Study Degree
by
Kathleen M. Saul

has been approved for
The Evergreen State College
by

__________________________
John Perkins
Emeritus Faculty

__________________________
Ralph Murphy
Member of the Faculty

__________________________
Dana Kelly
Idaho National Laboratory

__________________________
(Date)

ABSTRACT
The Renewed Interest in New Nuclear Construction in the United States:
Lessons from History, the Media, and Interviews
Kathleen M. Saul
In 2007, after a three-decade hiatus, companies in the United States started
applying to the Nuclear Regulatory Commission (NRC) for licenses to build and operate
new commercial nuclear power facilities. This thesis explores the factors underlying the
decisions to submit those applications and proposes a model that encapsulates those
factors. It begins with a review of the history of commercial nuclear power in the United
States to better understand the changing environmental, regulatory, and economic
contexts facing utilities in the 1960s and ‘70s and today. That historical review serves as
the basis for interviews with representatives of seven of the applicant companies
(AmerenUE, Dominion, Duke Energy, Entergy, PPL, Progress Energy Florida, and the
Tennessee Valley Authority (TVA)) as well as professionals in the nuclear industry.
Those interview results are combined with information gleaned from books, articles in
technical journals (such as Energy Policy, Power Engineering, and Nuclear News), news
articles (from The New York Times, the Wall Street Journal, Fortune magazine as well
on-line publications), company annual reports, and transcripts of hearings before the
Committee on Energy and Natural Resources of the U.S. Senate. This research reveals
that increased demand for electricity can lead companies to consider building new
capacity, and concern over carbon dioxide emissions can prompt interest in renewable
sources and nuclear power. However, utilities will not build new nuclear power plants
without (a) the changes in the nuclear reactor licensing process instituted in the 1990s,
and (b) either the federal financial incentives provided by the Energy Policy Act of 2005
or rate increases through the cost recovery mechanism of Construction Work in Progress
(CWIP).
This thesis then proposes a theoretical model for new nuclear reactor construction.
It draws on work in Political Ecology, a field that examines conflicts between people,
their productive activities, and nature, and the influence of cultural and political activity
on all three. More specifically, utilities choose to build new facilities to satisfy the
need/want for readily available electricity. Awareness of the potential for decreasing
supplies of oil and natural gas as well as pending legislation regulating carbon dioxide
emissions cause the utilities to look toward sources other than traditional coal- or gasfired plants. Companies will chose the nuclear option only if capital becomes available,
whether in the form of federal loan guarantees, production tax credits, or “construction
work in progress” (CWIP) financing. The model may be extended to other energy
investment decisions facing utility companies in the United States.
The Political Ecology Model of Energy Investments
Natural Resources/Environment

Technology

Capital Investment/Financing

Human Wants/Needs

Table of Contents
Preface………………………………………………………………………….………….1
1.0 Introduction

…...………………………………………………………………...3

2.0 Methods ….………………………………………………………………………….7
3.0 Nuclear Power Then and Now ……………………………………………………13
3.1 That Was Then: Understanding the Early Years of the U.S. Commercial Nuclear
Industry
……..…………………………………………………………..…14
3.1.1 The Atomic Energy Commission (AEC)
...………………………….14
3.1.2 Peaceful Power from Atomic Energy …..………………………………..16
3.1.3 Insurance Coverage Through the Price-Anderson Act ……………………17
3.1.4 Problems in Licensing and Construction
...………………………….18
3.1.5 Challenges in Operation
.…………………………………………...26
3.1.6 Changes in the Environmental and Energy Contexts …..………………..29
3.2 This is Now: The Nuclear Power Industry of the 2000s …...……………….36
3.2.1 The Institute of Nuclear Power Operations (INPO) ……………………37
3.2.2 Deregulation of Electrical Markets
……..……………………………..39
3.2.3 Utility Industry Consolidation ……...…………………………………….43
3.2.4 Reactor Design Standardization
..…………………………………..46
3.2.5 New Construction Issues
….......…………………………………….50
3.2.6 A One-Step Licensing Process …...……………………………………….51
3.2.7 Environmentally Sound Energy
.………………………………...…57
3.2.8 The Energy Policy Act of 2005
.…………………………………...61
3.2.9 Addressing Nuclear Power Plant Safety
..…………………………..65
3.3 More Information About Federal Loan Guarantees ………...………………….68
4.0 What the Electrical Companies and Utility Owners Tell Us
..………………..…77
4.1 NRG Energy ……...…………………………………………………………….78
4.2 Entergy Operations, Inc
….………………………………………………...83
4.3 Duke Energy ……………………………………………………………………88
4.4 Progress Energy Florida
..…………………………………………………..93
4.5 Tennessee Valley Authority (TVA) ……...…………………………………….97
4.6 Constellation Energy Group …………………………………………………..103
4.7 AmerenUE ….……………………………………………………………….108
4.8 Dominion Virginia Power …………………………………………………..112
4.9 PPL (formerly Pennsylvania Power and Light)
.………………………….115
4.10 Exelon Corporation …………………………………………………………..119
4.11 What Have We Learned? …..……………………………………………....124
5.0 What Do These Results Tell Us?

.………………………………………….131

Sources Cited ...………………………………………………………………………...149

Appendix 1: Reactor Ownership
Appendix 2: Timeline

….……….………………………………………173

………………….……………………………………….181

Appendix 3: Construction Extremes ……...….………………………………………..187
1.0 Westinghouse Nuclear Reactor Systems …………………………………..187
1.1 Comanche Peak …………………………………………………………..187
1.2 Diablo Canyon …...……………………………………………………...189
1.3 Watts Bar
...………………………………………………………...192
2.0 General Electric Nuclear Reactor Systems ……...…………………………...195
2.1 Fermi 2 ……...…………………………………………………………...195
2.2 Limerick 2
…………………………………………………………..197
Appendix 4: Partial Text of H.R. 1029 of 1985

…………………………………..201

Appendix 5: Brief Overview of New Reactor Design Features
…………………..205
1.0 Evolutionary Power Reactor From Areva Nuclear Power …………………..205
2.0 General Electric/Hitachi Advanced Boiling Water Reactor
…………..205
3.0 General Electric/Hitachi Economic Simplified Boiling Water Reactor …..206
4.0 Mitsubishi Heavy Industries U.S. Advanced Pressurized Water Reactor …..206
5.0 Westinghouse AP1000, Advanced Passive Boiling Water Reactor
…..207
Appendix 6: Select Portion of the Energy Policy Act of 1992

…………………..209

Appendix 7: Probabilistic Risk Assessment …………………………………………..211
Appendix 8: Interview Questions

…………………………………………………..219

Sources Cited in Appendices …………………………………………………………..223

List of Figures
Figure 1: The Average Days from Construction License Issuance to Reactor Operation
…...……………………………………………………………...…………….21
Figure 2: Construction Start Order versus Days from Construction License Issuance to
Reactor Operation
……………………………………………………………………22
Figure 3: Reactor Size (Capacity) and the Time Between Construction Licensing and
Reactor Operation
……………………………………………………………………23
Figure 4: Capacity Factors for Operating Reactors in the U.S., 1970s to the Present…..28
Figure 5: Unplanned Reactor Shutdowns Lasting More than Six Months ……………29
Figure 6: U.S. Crude Oil Prices, 1970 to 2008
……………………………………31
Figure 7: U.S. Natural Gas Prices, 1970s to the Present
……………………………32
Figure 8: Historic U.S. Coal Prices ……………………………………………………33
Figure 9: First Energy Nuclear Operating Company Performance Results ……………45
Figure 10: Southern Nuclear Operating Company Performance Results ……………45
Figure 11: Political Ecology Model of Agricultural Developments …………………..138
Figure 12: The Political Ecology of New Commercial Power Plants
…………..141
Figure 13: The Political Ecology of Energy in the United States ...………………...147
Figure 14: Sample Event Tree Diagram
…………………………………………..213

List of Tables
Table 1: Least Squares Linear Regression ……………………………………………24
Table 2: The State of the Nuclear Industry, Then and Now: A Comparison of Factors
Affecting the Industry in the 1960s – 1980s and in the 2000s
……………………68
Table 3: Factors Affecting Decision to Apply to Build New Nuclear Power Plants …..125

Acknowledgements
I wish to thank the following people for their contributions to this work:
My thesis committee
Dr. John H. Perkins, The Evergreen State College
Dr. Ralph Murphy, The Evergreen State College
Mr. Dana Kelly, Idaho National Laboratory
Interview participants
Dr. John Bickel, Evergreen Safety & Reliability Technologies, LLC
Danny Blanton, Entergy
Mike Cleary, AmerenUE
C.J. Fong, NRC Region II Construction Inspection Organization
Rick Grantom, South Texas Project
Hossein Hamzehee, NRC
Terry Johnson, Tennessee Valley Authority
Rick Kimble, Progress Energy Florida
David Lochbaum, Union of Concerned Scientists
Rita Sipe, Duke Energy
Richard Zuercher, Dominion
Anonymous, PPL
My friends and family, including
Greg Saul
Dr. David J. and Kae Hentges
Natalie Kopytko
And the people of Chernobyl and Kiev, Ukraine, who inspired my interest in nuclear
power.

vii

Preface
During the summer of 2007 I traveled to Chernobyl, Ukraine. The trip was part
of a course that delved into the basics of nuclear power and the details of the catastrophe
of April, 1986, when a fire and core melt-down at Unit 4 sent plumes of radioactive
materials high into the sky. That facility stood eerily idle, with makeshift scaffolding
holding up the hastily erected “sarcophagus” that covered the destroyed unit. A handheld dosimeter indicated that the area around the unit remained radioactive, despite the
best efforts of legions of Soviet men to bury and contain any debris from the accident,
any equipment being used on site at the time, and any trees or shrubs in the immediate
vicinity. In the nearby town of Pripyat, trees had grown up through cracks in the
sidewalks and children’s playground, where an unused ferris wheel watched quietly over
rusted bumper cars. Vines and trees also had begun to reclaim the old wooden houses
within the “exclusion zone” around the plant. Decaying signs pointed to abandoned
towns.
Many people remember the Chernobyl accident for dramatic efforts expended to
cap the reactor and relocate nearby residents; or for the amounts of radioactive strontium,
cesium, iodine, and other materials it spewed into the atmosphere, quantities detected
world-wide. Others recall it as the event that, on the heels of the melt-down at Three
Mile Island in Pennsylvania, finally brought an end to the first nuclear era in the United
States. For me, the visit to Chernobyl and discussions with people who had been there
that fateful day renewed my interest in commercial nuclear power.
Soon after returning, I was intrigued to see stories in The New York Times about
plans to construct two new nuclear units at the South Texas Project near Houston, TX. I

wondered why, so many years after construction of nuclear power plants came to a halt in
the U.S., a utility was again considering that option.
My Master’s thesis began to take shape.

1.0 Introduction
On September 20, 2007, NRG Energy became the first company in over three
decades to submit a complete application to the Nuclear Regulatory Commission (NRC)
for the construction and operation of a new nuclear power plant. 1 The company press
release of September 24 announced a “new day for the environment,” a way of
generating electricity without the carbon dioxide and greenhouse gas emissions
associated with coal-fired plants, a means of meeting the growing demand for power
without increased dependence on foreign sources of oil. 2
An application from the Tennessee Valley Authority (TVA), and its partners at
NuStart Energy Development, followed. Earlier, Craven Crowell, former Chairman of
the TVA, had expressed his view that new nuclear power was the only means of meeting
the nations’ appetite for electricity while protecting the environment. 3 According to
Craven, neither renewable sources nor conservation could supply enough power, and the
volatility of the price of natural gas made it impractical for baseload power.
By the beginning of 2009, the NRC had received applications to build 26 new
reactor units at 17 separate sites. The application for Florida Power and Light’s new
Turkey Point units followed in June of 2009. Were all applications driven by an interest

Vicki Vaughn, “Application is First in Decades for New Nuclear Reactor,” San Antonio
Express-News, September 24, 2007,
www.chron.com/disp/story.mpl/business/energy/516`662.html, (accessed October 8, 2007).
2

“NRG Energy Submits Application for New 2,700 Megawatt Nuclear Plant in South Texas,”
Company News Release, September 24, 2007, http://phx.corporateir.net/phoenix.zhtml?c=121544&p=irol-newsArticle_Print&ID=1054822&highlight=, (accessed
February 14, 2008).
3

“U.S. Power Industry Sees Nuclear Renaissance Near,” February 16, 2007,
www.reuters.com/article/bondsNews, (accessed March 19, 2009).

to reduce carbon dioxide and greenhouse gas emissions, and turn to sources of electricity
that were more environmentally friendly? After all, the belching smokestacks of coalfired electric plants were nothing new, having been the target of air quality regulation
enforcement of the 1970s. The discussion about climate change had been occurring for
decades, and debates over ratification of the Kyoto Protocol and its mandatory limits on
greenhouse gas production had occurred ten years earlier, in the mid-1990s. Those
events did not spur any new reactor construction applications.
Likewise, foreign oil imports have been increasing since the 1950s, save for a
brief period in the early 1980s. 4 Natural gas prices also have been fluctuating throughout
the late 1990s and the 2000s. But again, no reactor applications followed directly from
changes in either oil import level or gas prices.
What factor or combination of factors really motivated the interest in building
new nuclear power units, as demonstrated by construction and operation applications
submitted during 2007 and 2008? Was it truly due to concerns about the environment?
Was it caused by a surge in demand for electricity fueled by an American lifestyle that
relies on computers, computer games, electric coffee makers and can openers, large
screen televisions, cell phones and digital cameras whose batteries need frequent
recharging? Did increased reliance on computers in business and industry trigger the
interest, or was it based on declining domestic oil production and related fears over
national security (such as those that spurred interest in drilling in the Alaska National

Energy Information Administration’s Energy in Brief, “How Dependent Are We on Foreign
Oil?” April 23, 2009, http://tonto.eia.doe.gov/energy_in_brief/foreign_oil_dependence.cfm,
(accessed August 26, 2009).

Wildlife Refuge under President Bush)? 5 Or did something else generate the interest in
commercial reactor construction in the U.S.?
It was the goal of this research to explore the answers to those questions and to
develop a better understanding of why some utility companies and nuclear power plant
operators in the United States chose to submit applications to build and operate new
nuclear power plants. While the popular press and individual company annual reports
could offer some insights, there have been no systematic investigations that posed one set
of questions to the various companies about their rationale for submitting applications to
the NRC. Nor has there been an attempt to appreciate the decisions in a broader context
that includes the changes that have occurred in the nuclear industry since the accidents at
Three Mile Island, PA and Chernobyl, Ukraine. This study has attempted to do just that.

Bumiller, Elisabeth, and Jeff Gerth, “The Blackout: Legislation; Ambitious Bush Plan is
Undone by Energy Politics,” The New York Times, August 20, 2003,
www.nytimes.com/2003/08/20/, (accessed August 26, 2009).

2.0 Methods
The research for this thesis consisted of four main parts: (1) A review of the
history of the commercial nuclear power industry in the United States, with an eye
toward the factors that have changed over time and could have spurred new interest in
reactor construction, (2) Interviews with representatives of companies that had filed a
completed combined construction and operating license (COL) application with the NRC,
(3) A synthesis of the responses to the interview questions, and (4) Development of a
theoretical framework that could be used to understand the decision-making process for
building a new nuclear power facility in the United States.
The history of the nuclear power industry (Chapter 3) emerged from extensive
reading of books written on the subject, including Fermi’s Atoms in the Family;
Shouldering Risks by Constance Perin; Hostages of Each Other: The Transformation of
Nuclear Safety Since Three Mile Island by Joseph Rees; Cohn’s well-known book, Too
Cheap to Meter, and Nutall’s recent volume Nuclear Renaissance: Technologies and
Policies for the Future of Nuclear Power. Archived articles from The New York Times,
The Wall Street Journal, The Dallas Morning News, Newsweek, and other print and online newspapers and magazines provided snapshots of particular incidents and events at
the time of their occurrence. From technical journals, such as Power Engineering,
Nuclear News, and The Electricity Journal, came industry analyses of the overall
structure of the electrical generating industry as well as the prospects for a “nuclear
renaissance.” Transcripts of hearings before the Committee on Energy and Natural
Resources of the U.S. Senate and the Subcommittee on Energy Conservation and Power
of the U.S. House of Representatives furnished valuable insight into the arguments for

and against changing the licensing process for new nuclear reactors, standardizing new
reactor designs, and offering federal programs and providing federal funding to spur
interest in new reactor construction. Technical data and historical information came from
the internet sites of the American Nuclear Society, the Nuclear Regulatory Commission,
the Department of Energy, the Energy Information Association, and other industry
organizations.
Windows’ Excel program was used to analyze and graph construction data. Least
squares regression lines were added to Figures 1 and 2 to emphasize the upward
inclination of the points with year or order of construction start. The regression line in
Figure 3 shows the positive relationship between the reactor capacity (MW(e)) and
construction time.
The historical context framed the questions written for the telephone interviews
that followed. The questions were vetted through the Evergreen Human Subjects Review
Process before being asked of members of the nuclear power industry. (See Appendix 8
for the list of questions.) Although the questions served as the foundation of each
interview, some were omitted and others were added as each interview progressed. For
example, if a company had not yet chosen a final design for their reactor, questions about
the design were bypassed. In addition, time constraints limited the number of questions
that could be asked in some cases. Most interviews lasted between 45 minutes and one
hour.
The NRC’s list of COL applicants served as the basis for finding interview
candidates. Attempts to reach executives within the companies failed (phone calls were
not returned); calls to the media/press departments did result in interviews with

representatives from seven of the applicant companies: AmerenUE, Dominion, Duke
Energy, Entergy, PPL, Progress Energy Florida, and the Tennessee Valley Authority
(TVA).
Additional interviews related to specific areas of interest followed. Rick Grantom
of the South Texas Project and David Lochbaum (then with the Union of Concerned
Scientists) provided information about the Probabilistic Risk Analysis (PRA) now used in
the industry; C.J. Fong of the NRC answered questions about how PRA is being
incorporated into new reactor designs and licensing (see Chapter 3, Section 2, and
Appendix VI). Hossein Hamzehee, also of the NRC, added to the historical review with
his recollections of his days working at the Comanche Peak facility in Texas (Appendix
3), and Dr. John Bickel, who had worked at Millstone Unit 1 (Connecticut) and the NRC,
did likewise with descriptions of the early years of the U.S. nuclear power industry
(Chapter 3, Section 1).
Data from the discussions with company representatives were combined with
information gleaned from annual reports, press releases, and other media reports to create
a detailed picture of the many factors behind decisions to submit reactor construction
applications to the NRC. First, a list of the most important factors was generated based
on the interviews and readings. Next, those factors were grouped into broader categories,
as described below.
1. Environmental (including concerns over climate change, carbon dioxide
emissions, or the potential for regulation or taxing of those emissions);
2. Issues related to National Energy Security and the need to find domestic sources
of energy;

3. Financial matters, divided into three subcategories—the potential to secure
Federal Loan Guarantees or Production Tax Credits, and the Ability to Recoup
Costs During Construction;
4. Other regulatory factors related to new nuclear power plants: Risk Insurance,
Price Anderson Insurance Backing, and the new One-Step Licensing Process;
5. Meeting Demand, in terms of either the need for more baseload generation or
renewable sources not being capable of supplying enough electrical power;
6. Fuel-related factors—the Need for Fuel Diversity (not relying solely on coal or
natural gas or hydroelectric power), the Cost of Alternative Fuels;
7. Past Experience with Nuclear Reactors; and
8. Other.
In the third step of this process, the interview transcripts and printed documents
were coded according to the factors mentioned. If the transcript or document discussed
material under one of the above categories one or more times, it received a checkmark for
that category. Because of the exploratory nature of this research, the focus was not on the
precise number of times each reason was mentioned, but rather on the variety of reasons
cited for each applicant company. Thus, each interview or document might receive check
marks for several categories but only once for any given category. For example, if an
article revealed a company’s concerns over emissions from their coal-fired electric plants
as a factor in the choice of nuclear power, and later discussed the CEO’s anxiety over
potential cap and trade legislation, that article would receive only one check for the
Environmental category. Finally, the results for all companies were summarized in a
table (see Table 3).
An attempt to provide a cohesive framework for the results let to an examination
of theories from the Business Strategy and the Economics literature (briefly reviewed in
Chapter 5), but neither could explain the many different reasons behind a decision to seek

a COL from the NRC. Further research revealed the ideas of Political Ecology as
encompassing the breadth of factors uncovered in this research. 6 In particular, the model
advanced by Dr. J. H. Perkins in Geopolitics and the Green Revolution: Wheat, Genes,
and the Cold War demonstrated how the choice of technology mediates between human
wants and needs and the natural environment and natural resources.7 That model was
adapted to the nuclear power industry, an industry that must respond to people’s demand
for electricity while searching for ways of generating electricity that have less of an
impact on the natural environment.
In the sections that follow in this thesis, the first part of Chapter 3 discusses in
more detail the historical context of the first round of nuclear reactor construction in the
United States (that is, reactors planned and ordered before 1980). The second section of
that chapter reviews the changes that have occurred since that time. Chapter 3, Section 3
gives details about the Federal Loan Guarantee program as set forth in the Energy Policy
Act of 2005. Chapter 4 recounts the results of the interviews with company
representatives and the final chapter of this thesis explains the theoretical framework
developed to better understand the complexity of factors considered by utilities and
nuclear power companies when deciding to build a new nuclear plant.

Political Ecology adopts a multi-disciplinary approach to explore the conflicts between people,
their productive activities, and nature, and the influence of cultural and political activity on all
three. It stresses the interconnections of the historical, political, economic, social, and
biophysical contexts of environmentally-based problems.

John H. Perkins, Geopolitics and the Green Revolution: Wheat, Genes, and the Cold War, New
York, NY: Oxford University Press, 1997.

3.0 Nuclear Power Then and Now
Ren·ais·sance: n. A rebirth, revival; a renewal of life, vigor, interest.
Since the early 1990s, the popular press has been hinting at a renaissance in
nuclear power plant construction to meet the growing demand for electricity in the United
States. 8 With over 60 % of the U.S. population under the age of 44 and thus too young to
remember the first wave of nuclear reactor construction building (“Census 2000
Summary File (SF 1) 100-Percent Data: QT-P1. Age Groups and Sex: 2002,”), it
behooves us to revisit the context in which those original decisions were made and to
understand what has changed since then—to appreciate the “nuclear renaissance.” 9
Words from President Dwight D. Eisenhower’s 1953 speech to the United Nations
resonate even today: “The atomic age has moved forward at such a pace that every
citizen of the world should have some comprehension, at least in comparative terms, of
the extent of this development, of the utmost significance to every one of us.” 10
The first section that follows will highlight some of the important elements that
supported the decisions to construct nuclear power plants in the U.S. in the 1960s and
1970s. The second section will review how that situation has changed and why the time
may be ripe for another round of nuclear power plant construction in the 2010s.

Barrie McKenna, “Nuclear ‘Renaissance’ Seen Following Latest AECL Deal,” The Globe and
Mail, September 19, 1992, p. B2; “Nuclear Option Cannot Be Denied,” San Antonio ExpressNews, May 30, 1991, p. 1; “Go Slow on More Nuclear Power Plants,” U.S.A. Today, April 16,
1990, p. 08A.
9

“Census 2000 Summary File (SF 1) 100-Percent Data: QT-P1 Age Groups and Sex: 2000,”
http://factfinder.census.gov, (accessed 9/28/08).

“Atoms for Peace, Address by Mr. Dwight D. Eisenhower, President of the United States of
America, to the 470th Plenary Meeting of the United Nations General Assembly,”
www.iaea.org/About/history_speech.html, (accessed September 29, 2008).

3.1 That Was Then: Understanding the Early Years of the U.S. Commercial
Nuclear Industry 11
‘The Italian Navigator has reached the New World.’
‘And how did he find the Natives?’
‘Very friendly.’
With those simple yet powerful words, Professor Arthur Compton communicated
to his colleagues that the unthinkable had been accomplished. 12 On December 2, 1942,
Enrico Fermi, an Italian émigré, and his team had succeeded in creating a self-sustained
nuclear reaction at a makeshift reactor (or “pile”) in a squash court under the stadium at
the University of Chicago. 13 Twenty-five feet wide and 20 feet high, moderated by
graphite and controlled using cadmium rods, the reactor only produced a half-watt of
power. 14 But it ushered in a new age, an age in which the tiny nucleus of a uranium atom
could be harnessed to provide the energy for modern life.
3.1.1 The Atomic Energy Commission (AEC)
During the balance of World War II, focus shifted to the construction of nuclear
weapons. Then, in 1946, Congress passed the Atomic Energy Act, establishing the
Atomic Energy Commission (AEC) to oversee the peacetime uses of nuclear power in the

Note: In its early years, nuclear energy was widely referred to as “atomic” energy. However,
to be consistent throughout this document, I will use terms such as nuclear power, nuclear energy,
and nuclear technology except in the case of direct quotes.
12

Laura Fermi, Atoms in the Family: My Life with Enrico Fermi, Chicago, IL: The University of
Chicago Press, 1954. p. 198.
13

Ibid, p. 197; Enrico Fermi, “The Development of the First Chain Reacting Pile,” Symposium
on Atomic Energy and its Implications, November 17, 1945, Freeport, NY: Books for Libraries
Press, 1969, pp. 20 – 24.
14

“Chicago Pile One (CP-1),” http://www.atomicarchive.com/Photos/CP1/index.shtml, (accessed
February 3, 2009).

United States. The AEC was charged with formulating policies for nuclear energy,
conducting research and development, encouraging the commercial use of nuclear energy
for electrical generation, regulating its safety, and ensuring the safety of the American
public. 15 Although established as a civilian group and not an arm of the military, the
AEC could not escape its military roots: The initial post war plans centered on
developing dual-purpose military-civilian reactors and reactor powered U.S. Navy
submarines (under Captain Hyman G. Rickover) and Air Force jets. 16
The AEC realized that achieving a competitive nuclear power industry was of
national importance, to maintain U.S. technological superiority, to give the U.S.
advantage in bargaining with other nations, and to assure a supply of uranium ores from
foreign countries who looked to the United States for nuclear power technology. 17 But
how could the AEC involve industry in the development of nuclear power without
divulging military secrets? To what degree should the government finance the projects, if
at all? Who would own the reactors and the fissionable material they contained? And
was industry willing and able to take the lead in reactor development?
In the summer of 1953 the AEC decided that using a variation of the pressurized
water reactor of the naval propulsion systems would be its quickest path to designing a

Steven L. Del Sesto, Science, Politics, and Controversy: Civilian Nuclear Power in the United
States, 1946 – 1974, Boulder, CO: Westview Press, 1979; Steve Cohn, Too Cheap to Meter: An
Economic and Philosophical Analysis of the Nuclear Dream, Albany, NY: State University of
New York Press, 1997.
16

Richard G. Hewlett, and Jack M. Holl, Atoms for Peace and War, 1953 – 1961: Eisenhower
and the Atomic Energy Commission, Berkeley, CA: University of California Press, 1989, p. 188.

Ibid, pp. 23 and 194.

full-scale commercial power reactor.18 That winter, the Commission invited industry
members to submit proposals to participate in a project to create and operate that reactor
as part of a five-year program.
3.1.2 Peaceful Power from Atomic Energy
Representatives of world powers gathered at the United Nations in December of
1953 to discuss the spread of nuclear weapons and the threat that they posed to human
lives. In the speech now known as “Atoms for Peace”, Dwight D. Eisenhower proposed
that the build-up of nuclear weapons be reversed, that uranium and fissionable material
be controlled by a central, international agency, and that efforts be devoted to peaceful
uses of nuclear power. “[P]eaceful power from atomic energy is no dream of the future.
The capability, already proven, is here today.” He suggested that nuclear energy be
applied “to the needs of agriculture, medicine and other peaceful activities. A special
purpose would be to provide abundant electrical energy in the power-starved areas of the
world.” 19 These words signaled two significant post-war features of the use of nuclear
technology. First, nuclear power would be directed toward generation of electricity not
weapons, and second, an international body would be created to oversee the exchange of
information, technology, and materials. That body would be a clearinghouse, with
membership open to all nations, but would not have the authority to conduct or support
nuclear projects of its own. 20

Ibid, p. 192.
“Atoms for Peace, Address by Mr. Dwight D. Eisenhower, President of the United States of
America, to the 470th Plenary Meeting of the United Nations General Assembly.”
19

Hewlett and Holl, p. 217.

After “Atoms for Peace”, the AEC shifted its focus from dual-use military/civilian
nuclear reactors to the development of full-scale reactors for electricity production.
Pressure mounted to find reactors that could be deployed quickly as reliable power
sources. Economics were not of paramount concern. 21 With electricity production
foremost in its mind, the AEC supported development of a number of different reactor
designs and technologies, believing that the diversity would result in important
comparative data that could be used for decision-making when it came time for actual
construction. 22 Unfortunately, most of the data was gathered on small-scale laboratory
prototypes. Extrapolations from that data proved overly optimistic.
The year 1953 also saw the shift to private ownership of nuclear reactors. 23 The
AEC maintained ownership of the nuclear fuels, leasing them out to reactor owners. The
lease arrangement lasted until the passage of the Private Ownership of Special Nuclear
Fuels Act in 1964. 24
3.1.3 Insurance Coverage Through the Price-Anderson Act
Although the government, after much debate, backed the fledgling nuclear
industry financially, few insurers were willing to underwrite the construction and
operation of nuclear power plants. The risk was too great. Congress intervened with the
passage of the Price-Anderson Indemnity Act of 1957. The Act required that all nuclear
licensees carry the maximum level of primary insurance available to them (determined to
21

Steve Cohn, Too Cheap to Meter: An Economic and Philosophical Analysis of the Nuclear
Dream, Albany, NY: State University of New York Press, 1997.
22

Steven L. Del Sesto, Science, Politics, and Controversy: Civilian Nuclear Power in the United
States, 1946 – 1974, Boulder, CO: Westview Press, 1979.
23

Ibid, p. 54.

Ibid, p. 84.

be about $60 million). The government committed to contribute $500 million to cover
any claims in excess of that insurance amount. The 1975 extension of the Act replaced
the government funding with a pool of funds to which each licensee was required to
contribute. Those funds then would be available to provide “prompt and orderly
compensation” if members of the public or their property were to be harmed by a nuclear
incident (whether due to an accident at a power plant or a test or research reactor, or
during the transport of fuel to or from those facilities). The Act provided essential
protection for the suppliers to and operators of nuclear facilities, limiting the extent of
their liability in the event of a nuclear incident to the $60 million in required insurance
plus their contribution to the industry pool. It also safeguarded the public by forcing
those suppliers and operators/utilities to carry insurance rather than allowing them to
resort to filing bankruptcy in the face of accident claims (which would, in essence, have
forced taxpayers to pay for any damages). Based on assessments of the time, the known
risks were covered. 25
3.1.4 Problems in Licensing and Construction
The AEC was unprepared for the complexity of the task it faced when
commercial reactor license applications began arriving in the early 1960s. The AEC had
yet to establish general construction and safety guidelines for nuclear power plant
construction. As a result, each application required careful attention since architects and

“The Price-Anderson Act: Background Information,” American Nuclear Society, November
2005, www.ans.org, (accessed July 2, 2008); “Price-Anderson Act of 1957, United States,”
http://www.eoearth.org/article/Price-Anderson_Act_of_1957,_United_States, (accessed
September 29, 2008); “Price-Anderson Nuclear Indemnity Act,”
http://www.absoluteastronomy.com/topics/Price-Anderson_Nuclear_Industries_Indemnity_Act,
(accessed May 16, 2009).

engineers tailored each reactor design to specific electrical power needs and site
characteristics. All elements of the proposals were new and untested.
Following a safety evaluation, environmental impact review, antitrust inquiries,
and public hearings, the AEC issued a construction permit. 26 Later, when a plant had
been almost entirely completed, and after another public hearing, the AEC could issue an
operating license. For the first 10 to 12 commercial reactors (including Dresden 2,
Millstone 1, Oyster Creek, Palisades, and Pilgrim 1 (various AEC documents)), the AEC
chose to distribute “provisional” operating licenses. The AEC realized it did not yet have
the experience or technical information to know which designs were “good” or safe
enough, nor did they have a set of regulations to ensure the facilities would pose no
undue risk to the public. 27 By issuing a provisional license, the AEC allowed a plant to
start commercial operation but maintained the right to return and request changes and
upgrades to meet evolving criteria. Even plants that did receive a full-power operating
license from the AEC found themselves faced with amendments to those licenses for the
redesign or rebuilding of systems to meet new criteria. This licensing process (often
called the “two-step” licensing process) resulted in schedule delays and cost overruns as
requirements continued to change and disrupt construction. 28 For example, the 1975

“Our History: Atomic Energy Commission,” www.nrc.gov/about-nrc/history.html, (accessed
July 2, 2008).
27

John H. Bickel, Evergreen Safety and Reliability Technologies, LLC, Evergreen, CO,
Telephone Interview of March 16, 2009.
28

Richard Meserve and Ernest Moniz, “The Changing Climate for Nuclear Power in the United
States,” Bulletin of the American Academy of Arts and Sciences, Vol. 55, No. 2, Winter 2002, pp.
57 – 72: Rebecca Smith, “Politics and Economics: New Hurdle for Nuclear Plants; Licensing
System Seen by Utilities as Too Slow Amid Rush for Supply,” The Wall Street Journal, October
15, 2007, p. A.8.

Browns Ferry Al fire, spurred new regulations for fire protection (10 CFR 50, App. R),
and a critical accident at Three Mile Island, PA in 1979 both led to revised safety
requirements and rework for all plants not yet completed. In addition, the 1986 fire and
explosion at the Chernobyl Nuclear Station in Ukraine led to increased scrutiny of safety
and emergency response plans. 29
Unfortunately, each additional month of construction cost the utilities between
$23 million and $35 million (1980 dollars) in interest costs alone for plants whose total
costs had been estimated back in 1974 at about $775 million. 30 The two-step licensing
process also allowed nuclear opponents ample opportunity to delay work on a reactor
through litigation and even block the operation of a completed plant that had not yet
received an operating license, as in the case of the Shoreham plant on Long Island, NY. 31
As time progressed, the backlog at the AEC grew, and construction costs and durations
continued to climb.
Figures 1 and 2 show the trend of increasing construction time the later in the
queue the start of the reactor construction. (Note: Data are for units still in service as of
this writing.) Figure 1 displays a positive association between the year the construction
license was granted (between 1964 and 1979) and the time from issuance of that license

Diamond Stuart, “Chernobyl Causing Big Revisions in Global Nuclear Power,” The New York
Times, October 27, 1986; Diamond Stuart, “How Chernobyl Alters the Nuclear Equation,” The
New York Times, May 25, 1986, p. A1.
30

David Real, “Hearings Crucial to N-Plant, At Stake: Licenses for Comanche Peak,” The
Dallas Morning News, September 23, 1984, p. 37a; David Real, “Cost Estimate Raised for
Comanche Peak,” The Dallas Morning News, November 19, 1985, p. 1A; Matthew L. Wald,
“Building Reactors the New Way,” The New York Times, July 17, 1989, p. D.1.
31

Matthew L. Wald, “Shift Seen on Reactor Licensing,” The New York Times, March 25, 1989, p.
1.33.

and the reactor operation: the later the NRC issued the license, the longer it took to begin
generating electricity at the reactor.

Figure 1: Average Days from Construction
License to Operation
6000
5000
Days

4000
3000
2000
1000
0
1963

1965

1967

1969

1971

1973

1975

1977

1979

Year of Issuance

Figure 1: The Average Days from Construction License Issuance to Reactor
Operation
Based on Data from the U.S. NRC Information Digest, 2007 – 2008
(Least squares regression line added.)

Figure 2 shows a similar relationship between the days between license issuance and
operation, and the order in which the license was issued. The later the NRC issued the
reactor construction license, the longer it took to achieve operating status.

Figure 2: Construction License Issuance to
Operation
9000
8000
7000
Days

6000
5000
4000
3000
2000
1000
0
0

100

Order

Figure 2: Construction Start Order versus Days from Construction License
Issuance to Reactor Operation
Based on Data from the U.S. NRC Information Digest, 2007 – 2008
(Least squares regression line added.)

In addition, Figure 3 below indicates the positive relationship between the size of the
reactor unit (its capacity in MW(e)) and the construction time.

Days

Figure 3: Reactor Size (Capacity) and the Time
Between Construction Start and Grid Connection
9000
8000
7000
6000
5000
4000
3000
2000
1000
0
400

500

600

700

800

900 1000 1100 1200 1300 1400

Capacity (MW(e))

Figure 3: Reactor Size (Capacity) and the Time Between Construction Licensing
and Reactor Operation
Based on Data from the U.S. NRC Information Digest, 2007 – 2008
(Least squares regression line added.)

A series of multiple regression analyses conducted specifically for this thesis
demonstrated that three variables accounted for 65% of the variation in the time between
issuance of a construction license and beginning operations (adjusted R2 = 0.651, p value
< 0.0001): (1) Reactor capacity, (2) If operations began after the Three Mile Island
(TMI) accident in 1979, and (3) If the utility built a Westinghouse designed nuclear
reactor system. See Table 1.

Reactor Capacity (MW(e))

Regression Coefficient
2.22

Pre (1) / Post (0) TMI
Westinghouse Design (Y = 1 / N = 0)
Adjusted R2
p - value

-1317.98
391.6
0.65
< 0.0001

Dependent Variable = Time between issuance of a construction
license and beginning operations

Table 1: Least Squares Linear Regression

Adding a variable for the region of the country in which the reactor was located
(corresponding to the NRC regional divisions) did not change the explanatory value of
the regression model. Dividing the sample into two smaller ones, the first containing
reactors that began operations before TMI and the second only those that began
operations afterward, yielded somewhat different regression results. In both cases, the
variable for reactor capacity is statistically significantly related to the time between the
construction license and operations. Before TMI, a utility’s choice of Bechtel as
architect/engineer is negatively and somewhat significantly related to construction time
(p-value = 0.075), whereas after TMI, having a Westinghouse reactor design resulted in a
longer construction time (p-value = 0.078). What might be lurking behind these results?
Bechtel took an early lead in the commercial nuclear power industry in the late
1950s with its role in the construction of General Electric’s Boiling Water Reactor,
Dresden 1, in Illinois. 32 However, by the early 1960s, companies like Westinghouse and
General Electric (GE) began offing their clients something Bechtel could not--turnkey
contracts. Westinghouse and GE could perform the engineering, manufacture the
32

“1945 – 1959: Bringing Energy to the World,” http://www.bechtel.com/BAC-Chapter-3.html,
(accessed May 4, 2009).

turbines and generators, and build the facilities. Bechtel often became a subcontractor.
About half of Bechtel’s nuclear reactor jobs came from utilities hoping to build
Westinghouse or GE designs; the other half used Babco*ck and Wilcox or Combustion
Engineering designs. (In contrast, over 85% of the jobs for other architect/engineering
firms called for Westinghouse or GE reactors.) The Bechtel reactor projects tended to be
slightly smaller than the average (797 MW(e) versus 818 MW(e)) and took less time to
construct (2032 days versus an average of 2263 days). Those factors could lead to the
negative relationship observed in the regression analysis.
Over half of the reactors constructed after Three Mile Island used a Westinghouse
designed nuclear system. That alone could explain the positive relationship between
Westinghouse and the time between issuance of the construction license and reactor
operation. In addition, Westinghouse was associated with several very problematic
projects of that period: Comanche Peak 1 and 2 (TX), Diablo Canyon 1 and 2 (CA),
Seabrook Station (NH), and Watts Bar 1 (TN). Discovery of an earthquake fault near the
Diablo Canyon site slowed construction there as the facility design had to be modified to
meet new seismic standards. Quality assurance issues during construction led to a
shutdown at the Watts Bar site. Concerns over construction practices and lawsuits from
local citizens and environmental groups plagued Comanche Peak. (See Appendix 3 for
more details on these and two other projects with extremely long construction times.)
Thus, factors outside of direct Westinghouse control and not the Westinghouse design
itself often delayed bringing reactors on line.
In the end, the one factor that stands out as affecting the time it took to construct
nuclear power plants is the size (capacity) of the reactor. Whether examining the entire

sample of facilities or for smaller sub-samples of them, the larger the nuclear reactor, the
longer it took to build.
3.1.5 Challenges in Operations
Once the new nuclear powered electric generating plants came on line, they were
manned by operators who lacked experience. Most came from coal or natural gas plants.
According to a former CEO of Detroit Edison (owner/operator of the Enrico Fermi
facility), “No one foresaw the complexity of the modern-day nuclear power operations . .
. The feeling was that this new technology would just replace the boiler in a coal-fired
plant. The immense difference between running a nuclear plant and a conventional plant
was never dreamed of.” 33 Operators often treated the new facilities just as they had the
old fossil fuel plants, running them until they broke, waiting to do maintenance until
things “just didn’t work any more.” 34 That approach contributed to long periods of
shutdown for repairs, low levels of reactor availability (measured by capacity factors),
and high costs for the electricity that did get produced.
In addition, for 65 sites still existing today from that first round of construction,
there were 53 original ownership groups (utilities or power consortia). (See Appendix 1.)
The multi-site owners included companies like Commonwealth Edison, with reactors at
five locations, and Duke Energy with three different sites. However, most reactor
construction was undertaken by local utilities with their own particular needs,
requirements, and preferences. Consider the reactors constructed in New York in the

Perin, Constance, Shouldering Risks: The Culture of Control in the Nuclear Power Industry,
Princeton, NJ: Princeton University Press, 2006, p. 1.
34

Rees, Joseph, Hostages of Each Other: The Transformation of Nuclear Safety Since Three
Mile Island, Chicago, IL: University of Chicago Press, 1996. pp. 21-24; Perin, p. 3.

1960s. Niagara Mohawk Power chose a 825 MW(e) General Electric (GE) Boiling
Water Reactor for their Fitzpatrick site while Mohawk Power built a 621 MW(e) GE
Boiling Water Reactor. Rochester Gas and Electric selected a 498 MW(e) Westinghouse
Pressurized Water Reactors for R.E. Ginna, Consolidated Edison constructed a 965
MW(e) Westinghouse reactor for Indian Point, and the New York Power Authority built
a 985 MW(e) Westinghouse Pressurized Water Reactor at that same site. The wide
diversity of ownership and goals deterred sharing of knowledge gained during
construction or information about best practices once the reactors became operational.
The results of inexperience in building and operating reactors can be seen below
in Figure 4, Capacity Factors for Operating Reactors in the U.S. (Note: The Nuclear
Regulatory Commission defines the capacity factor for a nuclear reactor as the ratio of
the energy a reactor has actually produced to the energy that could have been generated at
continuous full-power operation during the same period. The lower the capacity factor,
the lower the electrical output of a reactor. 35 ) The average capacity factor hovered
around 60% for the first few decades of reactor operations. It was not until the early
1990s that reactor capacity factors began to increase, a full twenty years after the first
reactors came on line. And, a part of that increase can be attributed to factors other than
increased experience with reactor operations. For example, as a result of Probabilistic
Risk Assessments of the early 1990s, the NRC began allowing reactors to continue
operating rather than shutting down during routine maintenance activities. 36 Keeping a
reactor on line increases its energy output and thus the capacity factor.

“Capacity Factor-Net,” http://www.nrc.gov/reading-rm/basic-ref/glossary/capacity-factornet.html, (accessed January 29, 2009).
36

Dana Kelly, Idaho National Laboratory, Conversation of January 30, 2009.

Averag e Cap acity F acto r,
Percen t

Figure 4: Capacity Factors for Operating Reactors in the U.S.
100
90
80
70
60
50
40
1970

1975

1980

1985

1990

1995

2000

2005

2010

Year

Figure 4: Capacity Factors for Operating Reactors in the U.S., 1970s to the Present
Data Source: “Nuclear Power Plant Operations, 1957 - -2006,” from the Energy
Information Administration

Figure 5 contains the numbers of unplanned reactor shutdowns of six months or
more, by year, per plant. Such shutdowns reflect time the reactor was out of service for
issues not related to planned maintenance, modifications, or refueling. Dividing by the
number of plants in operation at year-end eliminates variations due to the number of plant
openings and closures. According to Nils J. Diaz, former Chairman of the NRC,
unplanned shutdowns of the early 1980s resulted from material degradation problems and
post-Three Mile Island regulatory actions. 37 In the mid-80s, a push to increase reactor
capacity and the need to amend reactor operating licenses led to an increase in
shutdowns. By the late 1980s and early 1990s, design issues and material degradation
were the primary issues. In addition, of the unplanned shutdowns since 1979 that lasted
37

Nils J. Diaz, “Excellence in Safety Management (Ensuring the Assurance of Adequate
Protection and Enhancing Public Confidence),” Speech Before the Institute of Nuclear Power
Operations, Atlanta, GA, November 3 – 4, 2004, NRC News, No. S-04-018, U.S. Nuclear
Regulatory Commission, Washington D.C.

more than one year, about 50% resulted from design or licensing related issues. Thus,
particularly in the early years of the industry, inexperience with reactor designs and with
the potential range of problems that could result from increased reactor usage led to lost
power production.

Unplanned Shutdowns
per Reactor

Figure 5: Unplanned Shutdowns of Six Months or More,
per Reactor
0.2
0.15
0.1
0.05
0
1975

1980

1985

1990

1995

2000

2005

2010

Year

Figure 5: Unplanned Reactor Shutdowns Lasting More than Six Months
A Look Back
Based on Data from Diaz, PowerPoint of November 3, 2004

3.1.6 Changes in the Environmental and Energy Contexts
Two additional factors shaped the first wave of nuclear power plant construction
in the United States. First, in 1963 the initial version of the Clean Air Act was enacted
under the auspices of the U.S. Public Health Service. Under this Act, the federal
government began to implement and enforce regulations setting limits on certain air

pollutants known to affect human and environmental health. 38 Initially, the act focused
on sulfur dioxide and nitrous oxide, chemicals known to react with water to form
particles know as “acid rain.” 39 In later years it expanded its purview to include
particulates (soot, smoke), ground level ozone (smog), carbon monoxide, sulfur and
nitrogen oxides, and lead. 40 These subsequent versions of the Act gave the
Environmental Protection Agency (EPA), established in 1970, the authority to police the
emissions coming from chemical plants, steel mills, utilities, and manufacturing facilities,
and to levy fines and require equipment modifications to bring operations into
compliance with EPA emissions standards. Electric utilities felt increasing pressure to
clean up their operations, either by retrofitting their plants with often-costly pollution
control equipment or by investing in electrical generating technology that utilized fuels
with lower levels of pollution, such as nuclear power.
The energy crisis of the early 1970s and resultant prices of fossil fuels also
spurred the nuclear reactor construction boom. At the time, electric producers were
switching away from coal, to oil and natural gas, due to increased costs of mining,
transportation problems, and waste, environmental and emissions issues associated with
mining and processing coal. 41 That put a drain on domestic oil reserves. The Middle

“Understanding the Clean Air Act,” www.epa.gov/air/caa/peg/understand.html, (accessed June
23, 2008).

W. J. Nutall, Nuclear Renaissance: Technologies and Policies for the Future of Nuclear
Power, London, England: Taylor and Francis, 2004.
40

“Cleaning Up Commonly Found Air Pollutants,” http://www.epa.gov/air/caa/peg/cleanup.html,
(accessed June 23, 2008).

Paul W. McCracken, “The Energy Crisis,” American Enterprise Institute Roundtable of
September 25-27, 1973, Washington D.C.: American Enterprise Institute for Public Policy
Research, 1974. p. 7.

East Oil Embargo of 1973-74 compounded those shortages. 42 The world price of oil shot
up from almost $14 (all fuel cost figures given in 2008 dollars) per barrel in 1970 to over
$42 per barrel by January of 1974—an over 200% increase.43 (See Figure 6.) Oil prices
peaked again in the late 1970s and early 1980s, mainly as a result of the Iranian
Revolution (resulting in the ouster of the Shah, who had had close ties to American Oil
Companies, and the loss of two to 2.5 million barrels of oil per day). 44
Figure 6: Crude Oil Prices, 2008 Dollars
$120.00

Crude Oil Price
(dollars/barrel)

$100.00
$80.00
$60.00
$40.00
$20.00
$1965

1970

1975

1980

1985

1990

1995

2000

2005

2010

Year

Figure 6: U.S. Crude Oil Prices, 1970 to 2008
Based on Data From “Crude Oil Prices, 2006 Dollars”
42

During the embargo, Arab members of the Organization of the Petroleum Exporting Countries
(OPEC) stopped shipping oil to the United States and the Netherlands due to their support of
Israel during the “Yom Kippur” War with Egypt in October of 1973. (Greg Burt, “The Arab Oil
Embargo: What Happened and Could it Happen Again?’ August 9, 2009,
http://www.heatingoil.com/wp-content/uploads/2009/09/the_arab_oil_embargo.pdf, (accessed
December 20, 2009).
43

“Crude Oil Prices, 2006 Dollars,” www.wtrg.com/oil_graphs/oilprice1970.gif, (accessed May
3, 2009).
44

“The Iranian Revolution,” http://www.wsu.edu/~dee/SHIA/REV.HTM, (accessed December
20, 2009); “The Iranian Revolution: King Pahlavi (the Shah) against Dissent,”
http://www.fsmitha.com/h2/ch29ir.html, (accessed December 20, 2009); “Oil Price History and
Analysis,” http://www.wtrg.com/prices.htm, (accessed December 20, 2009).

Prices for natural gas also increased in the 1970s and 1980s as a result of the
energy crisis and of utilities changing their fuel source from oil to gas (Figure 7). In
January of 1976, 1000 cubic feet of natural gas cost $0.54; by 1983, that price was up
almost 400% to $2.66. 45 Even the real U.S. coal prices rose just over 75%, from $29 per
short ton in 1973 to almost $53 by 1978. 46

Natural Gas Price, dollars per 1000 ft3

Figure 7: Natural Gas Price, 2008 dollars
$9.00
$8.00
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$1975

1980

1985

1990

1995

2000

2005

2010

Year

Figure 7: U.S. Natural Gas Prices, 1970s to the Present
Based on Data From “Natural Gas Navigator: U.S. Natural Gas Wellhead Price
(Dollars per Thousand Cubic Feet)”

“Natural Gas Navigator: U.S. Natural Gas Wellhead Price (Dollars per Thousand Cubic Feet),”
http://tonto.eia.doe.gov/dnav/ng/hist/n9190us3m.htm, (accessed October 10, 2008).
46

“Table 7.8: Coal Prices, 1949 – 2008,” Annual Coal Report of the Energy Information
Administration, http://www.eia.doe.gov/emeu/aer/txt/stb0708.xls, (accessed May 14, 2009).

Price of Coal, per ton

Figure 8: Average Price U.S. Coal Sales, real, inflation
adjusted (2008 year dollars)
60
50
40
30
20
10
0
1940

1950

1960

1970

1980

1990

2000

2010

Year

Figure 8: Historic U.S. Coal Prices
Based on Data From the Annual Coal Report of the Energy Information
Administration

It is difficult to directly compare the cost per kilowatt-hour of electricity
generated by coal, natural gas, oil, and nuclear power due to a myriad of factors including
the distance the fuel must be transported, the quality of the fuel, and whether or not the
power plant is operated to supply base load capacity, and whether nuclear power costs
include future decommissioning costs. 47 Still, a potential shortage of oil, the need to add
scrubbers to clean up the emissions from coal fired plants, and the rising costs of all fuels
made nuclear an increasingly economical alternative.
The unrest in the Middle East in the 1970s not only raised fuel costs and the cost
of petroleum-derived goods, but also elevated concerns about the security of American
fuel supplies. The newly enacted environmental regulations made some oil producers
47

Charles Komanoff, Power Plant Performance: Nuclear and Coal Capacity Factors and
Economics, New York: Council on Economic Priorities, 1976. pp. 7-8.

reluctant to invest in new facilities—the funds might be needed to upgrade older facilities
to reduce emissions and to produce the new type of fuel required by those regulations. 48
Growth in refining capacity lagged growth in demand. Thus, more and more oil (and, by
association, the gasoline refined from it) came from outside the U.S. In fact, by the early
1970s, the U.S. imported about one third of the oil it used.49 With tensions in the Middle
East threatening a major source of American energy, utilities began to look to domestic
sources of fuel, such as the Alaskan North Slope fields, with an increased sense of
urgency. 50
Tensions also mounted at the Atomic Energy Commission. The AEC had been
charged not only with advancing the commercial uses of nuclear energy but also with
regulating those uses. Concern over those conflicting missions led to the Energy
Reorganization Act of 1974 and the formation of two separate bodies: (1) The Nuclear
Regulatory Commission (NRC), to promote human health and safety, to oversee the
licensing of nuclear facilities and their safe operation, and to manage nuclear wastes; and
(2) The Energy Research and Development Administration, whose mission of advancing
and expanding the industry was taken over by the Department of Energy in 1977. 51

McCracken, p. 6.

Ibid, p. 27.

Production from the North Slopes fields in Alaska began in 1977. (“Supply,” U.S. Energy
Information Administration,
http://www.eia.doe.gov/pub/oil_gas/petroleum/analysis_publications/oil_market_basics/supply_t
ext.htm, (accessed December 20, 2009).)
51

“Federal Government, Atomic Energy Commission, 1946-1977,” http://www.u-shistory.com/pages/h1813.html, (accessed October 25, 2008); “Our History: Atomic Energy
Commission,” www.nrc.gov/about-nrc/history.html, (accessed July 2, 2008).

As the first decades of commercial nuclear power in the United States drew to a
close, the industry, which had devoted itself to the peaceful use of the atom that had been
so proudly extolled by President Eisenhower, was saddled with cost overruns, low levels
of productivity, and canceled plans for expansion. It faced a public very concerned about
the safety of nuclear power (primarily resulting from the accidents at Three Mile Island
and Chernobyl). Prices for the competing fossil fuels--oil, coal, and natural gas--had
peaked in the late 1970s and early 1980s, but quickly dropped off. Would the industry
survive?

3.2 This is Now: The Nuclear Power Industry of the 2000s
The first part of this chapter reviewed the contextual elements supporting the
decision to construct nuclear reactors in the 1960s, 1970s, and 1980s. The interest in
building nuclear power plants waned as costs mounted and it became apparent that the
plants were neither as easy to operate nor did they produce as much electricity as had
been expected. No new reactor construction was begun after 1977. 52 Even so, the
regulatory framework supporting the existing reactors continued to change and develop.
This section will focus on the post-Three Mile Island regulatory and government policy
changes, industry reorganization, establishment of industry-specific organizations, and
updates of processes and procedures within the NRC and reactor management.
The accident at Three Mile Island brought issues of nuclear power plant safety to
the forefront. Under President Jimmy Carter, the Kemeny Commission investigated the
accident. That Commission concluded that the AEC/NRC’s approach failed to
adequately ensure the safety of the public or the power plants. It recommended the
creation of a program that would (1) Establish appropriate safety objectives for the
nuclear industry and standards of excellence against which operating performance could
be compared; (2) Gather, review, and analyze performance data from all the nuclear
power plants; and (3) Build an industry-wide communications network to share that and
other information. 53 Those recommendations gave rise to the Institute of Nuclear Power
Operations (INPO) in 1979.

Information Digest, 2007 – 2008, U.S. NRC, NUREG – 1350, Vol. 19, August 2007,
Washington D.C.: Office of the Chief Financial Officer, U.S. Nuclear Regulatory Commission.
53

“About Us,” www.inpo.info/AboutUs.htm, (accessed May 21, 2008); “Nuclear Industry
Organizations,” www.nucleartourist.com/basics/inpo.htm, (accessed May 21, 2008).

3.2.1 The Institute of Nuclear Power Operations (INPO)
Unlike the AEC or the NRC, INPO is neither a government agency nor is it
located in the Washington D.C. area. Instead, it is a not-for-profit organization
headquartered in Atlanta, GA. Although INPO employs nuclear professionals, many
with past experience working at commercial power plants or with the NRC, and although
it counts all operating nuclear power plants in the United States among its members,
INPO strives to maintain independence from those constituencies it serves. The NRC
continues to license and regulate the industry, and attend to legal issues, and the
Department of Energy (DOE) promotes the use of nuclear power, allowing INPO to focus
its efforts on continual improvement in plant safety and reliability.
Self-regulation by peer review lies at the heart of the INPO philosophy. 54 Each
member plant undergoes inspection by a panel of INPO and industry personnel every 18
to 24 months. 55 Each plant gets evaluated on the caliber of its workers, the quality of its
programs and procedures, and the effectiveness of its management. Plant managers then
receive suggestions for improvements, suggestions they are expected to follow. 56 INPO
also requires plant managers to provide qualitative performance data on a quarterly basis
and then makes all of that information available to all INPO members. 57 The managers
and industry executives can compare their plants’ performances with those of their
competitors and with the INPO standards of excellence and can readily understand where
54

Perin, p. i.

“Nuclear Industry Organizations,” www.nucleartourist.com/basics/inpo.htm, (accessed May 21,
2008).
56

“About Us,” www.inpo.info/AboutUs.htm, (accessed May 21, 2008); Perin, p. 10.

Perin, p. A-8.

changes need to be made. Peer pressure compels them to adopt the “best practices” of
the better performers.
INPO does have a formal memorandum of understanding with the NRC for
exchange of information, reactor reviews, and summary level or trend data. 58 INPO also
shares information with international agencies through its international equivalent, the
World Association of Nuclear Operators (WANO). WANO members exchange
experiences and analyses to help improve the safety of nuclear reactor facilities
worldwide.
INPO also took on some of the responsibility for the on-site training of nuclear
plant personnel. The National Academy for Nuclear Training was established in 1985 to
integrate training programs for all U.S. nuclear plant workers and supervisors. 59
Although plants can develop training programs tailored to their site and particular
equipment, INPO provides the accreditation. 60 For example, at the Duke Power Co.,
trainees spend four years in training before taking their reactor operator licensing exam:
three years of apprenticeship and one year of classroom, simulator, and on-the-job
training. Those individuals must then take a refresher exam each year to renew their
license. Exelon Nuclear favors reinforcement of classroom teaching with “dynamic
learning activities”—putting people in situations similar to those they would find on the

Ibid, p. 12.

“Nuclear Plant Personnel Training Facts,”
www.nukeworker.com/study/radiation_faqs/Training_Facts.shtml, (accessed July 2, 2008).
60

Matthew L. Wald, “Can Nuclear Power be Rehabilitated?” The New York Times, March 31,
1991, p. 3.6.

job, whether in a real plant setting or using simulators. 61 Those experiences help trainees
practice correct behaviors and appropriate responses in any situation they might face.
3.2.2 Deregulation of Electrical Markets
Nuclear power plant performance did improve through the 1980s and 1990s
(Figures 4 and 5), in part due to INPO oversight, in part due to improved operator
training, but also due in part to pressures put on many of the utilities by deregulation of
the electricity markets, made possible by the Energy Act of 1992 and Federal Energy
Regulatory Commission (FERC) Orders. 62 Under regulation, state Public Utility
Commissions determined the gross revenue, and thus rate of return, that each utility
would be permitted to receive from customers. 63 The rate of return would cover the
operating expenses and cost of services plus an operating income and profit for the
utility. 64 The rate of return might also cover expenses being incurred during construction
of new facilities or equipment upgrades. 65 Unfortunately, because utilities could pass
costs on to their customers, there was little incentive to reduce costs or increase

Rick Michal, “Coovert: Human Performance Training at Exelon Nuclear,” Nuclear News,
January 2003, pp. 23 – 25.
62

Energy Policy Act of 1992, H.R. 776, http://thomas.loc.gov/cgibin/query/F?c102:1:./temp/~mdbs0MIIy3::, (accessed November 12, 2008).
63

Arturo Gandara, Electric Utility Decision-making and the Nuclear Option, Santa Monica, CA:
Rand, 1977; “A Primer on Electric Utilities, Deregulation, and Restructuring of U.S. Utilities
Markets,” U.S. Department of Energy, May 2002, Version 2.0, http://www/eren.doe.gov/femp,
(accessed July 23, 2008). pp. 5.2 – 5.9.

Saunders Miller, The Economics of Nuclear and Coal Power, New York, NY: Praeger, 1976.
pp. 61-63; “A Primer on Electric Utilities, Deregulation, and Restructuring of U.S. Utilities
Markets,” U.S. Department of Energy, May 2002, Version 2.0, http://www/eren.doe.gov/femp,
(accessed July 23, 2008). pp. 5.2 – 5.9.
65

Gandara, p. 73.

operational efficiencies. 66 In contrast, under deregulation, the workings of the wholesale
market for electricity, and not utility commissions, would determine utility revenues.67
Deregulation promised lower retail prices for electricity through competition in
the industry, improved operations and plant management, and consumer choice of
electric suppliers. 68 That did not occur. Some smaller utilities merged in order to survive
competition. Other utilities sold their electric generation facilities and concentrated on
the transmission and distribution of power instead. 69 Consumers did not get the promised
choice of suppliers. In areas like Houston, TX, regulators required utilities to sell their
power plants. Investment firms snatched up the power plants and later sold them for a
profit. 70 Some utilities, unable to generate a profit in the competitive environment, once
again fell under government regulation. According to [then] CEO of Duke Energy, “The
dream of an integrated gas and power generation industry serving free and open markets

David Cay Johnston, “In Deregulation, Plants Turn into Blue Chips,” The New York Times,
October 23, 2006; Lester B. Lave, Jay Apt, and Seth Blumsack, “Deregulation/Restructuring Part
I: Reregulation Will Not Fix the Problems,” The Electricity Journal, Vol. 20, No. 8, October
2007, pp. 10 – 12.
67

Seth A. Blumsack, Jay Apt, and Lester B. Lave, “Lessons from the Failure of the U.S.
Electricity Restructuring,” The Electricity Journal, Vol. 19, No. 2, March 2006, pp. 15 – 32;
Severin Borentstein, “The Trouble with Electricity Markets: Understanding California’s
Restructuring Disaster,” The Journal of Economic Perspectives, Vol. 16, No. 1, Winter 2002, pp.
191 – 211.
68

Rebecca Smith, “States Face Fights as Caps Expire on Electric Rates; Deregulation Deadlines
Highlight Disparities Between Customers, Utilities,” The Wall Street Journal (Eastern Edition),
August 17, 2004, p. A.1.
69

Matthew Brown, “Transforming the Electricity Business,” State Legislatures Magazine, April
1999, http://www.ncsl.org/programs/pubs/499elec.htm, accessed July 22, 2008; “A Primer on
Electric Utilities, Deregulation, and Restructuring of U.S. Utilities Markets,” U.S. Department

of Energy, May 2002, Version 2.0, http://www/eren.doe.gov/femp, (accessed July 23,
2008).
70

David Cay Johnston, “In Deregulation, Plants Turn into Blue Chips,” The New York Times,
October 23, 2006.

with a balance of hard assets and trading has turned into a nightmare.” 71 Dreams of a
competitive electrical market had faded.
Although nuclear power plants improved their efficiency during the period (as
reflected in increased capacity factors, Figure 4), other issues negated their impact on
electricity prices. For example, not all deregulated states obtained electrical power from
nuclear facilities—Delaware and Maine among them. 72 In most of the other deregulated
states, nuclear power contributed less than half of the total electric demand. Without
similar efficiency improvements in their coal or natural gas-fired power plants, suppliers
overall costs did not decrease and consumer prices did not come down. In fact, in the
end, many consumers paid the price of deregulation through higher, monopolistic, prices
for electricity. (Texans, for example, saw their electric bills rise 56 to 80%. 73 )
Many states enacted price caps to shield customers from high prices during the
transition from regulated to deregulated electric markets, but those caps began to expire
in the mid-2000s. When caps lifted in 2001 in Montana, retail customers went from
paying some of the lowest prices in the nation to having among the highest electric rates

“Duke Energy 2003 Summary Annual Report,” http://www.dukeenergy.com/pdfs/Duke_Energy_2003_Annual_Report.pdf, (accessed March 13, 2009).
72

Nuclear Energy Fact Sheets,
http://www.nei.org/resourcesandstats/documentlibrary/reliableandaffordableenergy/factsheet/,
(accessed January 27, 2010).
73

Tom Fowler, and Janet Elliott, “Deregulation Debate: Many Texas Consumers Feel
Competition in the State’s Energy Markets has Been a Costly Failure,” Houston Chronicle,
October 8, 2001, www.chron.com, (accessed 10/29/08); Rebecca Smith, “States Seek Ways to
Curb Surging Electricity Bills; Many Consumers Face Jolt Arising from ‘90s Changes;
Connecticut’s 22 % Increase,” The Wall Street Journal (Eastern Edition), February 28, 2006, p.
A.1.

in the region, a 40 % increase. 74 Rates in Illinois rose 30 to 50 % in January of 2008 and
Maryland customers faced increases of over 70 % until the legislature intervened. 75
Although some argue that the increases reflect the change in energy prices during the
period the price caps were in effect, an Associated Press (AP) analysis indicates that the
retail rate gap between regulated and unregulated states did indeed increase during that
time. Energy prices alone did not explain the difference. Even the large industrial
customers saw no price advantages under deregulation. 76
Giving customers the option to choose their own power supplier also proved
easier in theory than in practice. Many found little financial benefit to switching
providers and others just did not want to do the research and make the arrangements to
switch. 77 In addition, some of the new power providers left the market when the volume
of residential customers could not sustain their businesses. Those customers ended up
back with their original electric providers.

Matt Gouras, “Deregulation Has Stung Montanans; The State Went From Having Some of the
Lowest Electricity Rates to Among the Highest in the Region. Efforts to Undo the Effects Face
Hurdles,” Los Angeles Times, March 7, 2006, p. C.5; Ryan Keith, “Energy Deregulation Hits
Consumers Hard; As States Halt Caps on Electricity Prices, Anticipated Decreases Don’t
Materialize,” The Washington Post, May 6, 2007, p. A. 16.
75

Keith, p. A. 16.

Jay Apt, “Competition Has Not Lowered U.S. Industrial Electricity Prices,” Electricity Journal,
Vol. 18, No. 2, March 2005, pp. 52 – 61.
77

Brooks Barnes, “What Happened?—Nothing Personal: Many Individual Consumers Have
Come to a Simple Conclusion About Electricity Deregulation: Big pain, little gain,” The Wall
Street Journal (Eastern Edition), September 17, 2001, p. R12.

Under regulation, utilities could obtain low cost capital for investments and
expansion and could pass the costs on to customers through their rate of return. 78
Deregulation has made it more difficult to recoup those costs, increasing the risk
associated with investments and thus the interest rates utilities must pay. One would
expect that construction of new nuclear power plants would occur mainly in regulated
environments. However, of the twelve applications received by the NRC by the end of
November 2008, half were in regulated states (North and South Carolina, Florida,
Georgia, Louisiana, Mississippi, and Missouri) and half in deregulated states (Texas,
New York, Michigan, and Pennsylvania). Other factors, such as the proximity to centers
of population growth and to the transmission grid, must be at work.
3.2.3 Utility Industry Consolidation
Industry consolidation and reorganization spurred by deregulation and the 2006
repeal of the Public Utility Holding Act of 1935 also affected the nuclear power
generators. 79 Under the Public Utility Holding Act, generating plants and distribution
facilities owned by a utility had to be physically interconnected or capable of being
interconnected, and had to be confined to a single area or region. With that regulation no
longer in force, utilities could branch out geographically. A company like NRG Energy
can now own natural gas, coal, wind, oil, and nuclear facilities in states as far-flung as
Texas, Louisiana, Illinois, California, Nevada, New York, Pennsylvania, Connecticut,

William J. Hausman, and John L. Neufeld, “The Market for Capital and the Origins of State
Regulation of Electric Utilities in the United States,” The Journal of Economic History, Vol. 62,
No. 4, December 2002, pp. 1050 – 1073.
79

Adam Vann, “The Repeal of the Public Utility Holding Company Act of 1935 (PUHCA) and
its Impact on Electric and Gas Utilities,” CRS Report for Congress, Congressional Research
Service, The Library of Congress, Washington, D.C., November 20, 2006.

Delaware, Maryland, and Massachusetts. This type of industry upheaval has meant that
only 31 different groups/organizations owned the U.S. nuclear power plants by the
summer of 2008, down from the original 53. For example, PECO Energy and Unicom
merged in 2000 to form Exelon Corporation, with a fleet of 14 reactors. 80 In 2008,
Exelon tendered an offer for NRG Energy Inc., part owner of two Texas plants, in a bid
to become the nation’s largest power company. 81 The NRG Board of Directors and its
stockholders rejected that bid during the 2009 annual meeting. 82
In addition, smaller utilities have ceded operation of their nuclear power plants to
firms specializing in plant management. First Energy Nuclear Operating Company,
incorporated in 1988, now oversees the two reactors at Beaver Valley, PA (on behalf of
Pennsylvania Power and Ohio Edison), and reactors at David Besse and Perry, both in
Ohio (for Cleveland Electric). Southern Nuclear Operating Company (established in
1990) manages Alabama Power’s Farley reactors, as well as Georgia Power’s Hatch and
Vogtle facilities. Theoretically, shared management should increase the exchange of
technical information and sharing of experiences regarding equipment repairs and
refueling, and should result in improved plant performance. 83 Figure 9 indicates that
shared management did not necessarily benefit all reactors in the First Energy Nuclear
fleet—the average capacity factor for the Perry and Beaver Valley units fell below the

Mark Holt, “CRS Issue Brief for Congress: Nuclear Energy Policy,” Washington D.C.:
Congressional Research Service, Library of Congress, March 15, 2001. p. CSR-2.

Mark Williams, “Utilities Consolidation Goes On: Exelon for NRG,”
http://www.biz.yahoo.com/ap/081020/exelon_nrg_energy.html, (accessed October 21, 2008).
82

“Exelon Drops its Bid for NRG Energy,” The New York Times, July 21, 2009.

Robert Peltier, “Nuclear Renaissance Continues,” Power, Vol. 148, Issue 5, June 1, 2004, p. 32.

national average throughout most of the 1990s. In contrast, shared management may
have contributed to the consistently good capacity factor performance of Southern
Nuclear reactors in the 1990s (Figure 10).

Average Capacity Factor, %

Figure 9: First Energy Nuclear Operating Company
100
90
80
70
60
50
40
30
20
10
0

Beaver Valley 1
Beaver Valley 2
David Besse
Perry
All U.S. Reactors

1972- 1975- 1978- 1981- 1984- 1987- 1990- 1993- 1996- 1999- 2002- 200574
77
80
83
86
89
92
95
98
01
04
07
Year

Figure 9: First Energy Nuclear Operating Company Performance Results
Source: Blake
Figure 10: Southern Nuclear Operating Company

Average Capacity Factor, %

100
90
Farley 1
80

Farley 2
Hatch 1

Hatch 2
Vogtle 1

Vogtle 2
All Reactors

50
40
1972- 1975- 1978- 1981- 1984- 1987- 1990- 1993- 1996- 1999- 2002- 200574
77
80
83
86
89
92
95
98
01
04
07
Year

Figure 10: Southern Nuclear Operating Company Performance Results
Source: Blake

3.2.4 Reactor Design Standardization
Why has reactor performance not always improved under specialized
management teams? One reason may be the plethora of reactor designs built and
operating in the United States. First Energy Nuclear Operating Company supervises
work at two Westinghouse pressurized water reactors, one Babco*ck and Wilcox
pressurized water reactor, and a General Electric boiling water reactor. Thus, learning
from one site does not translate well to another. Even within sites, experience with one
reactor may not apply to another. Dominion’s Millstone, CT plant has one Westinghouse
pressurized water reactor and one Combustion Engineering pressurized water reactor.
The two designs have different processes and protection systems and are susceptible to
different types of stresses, cracks, or failures, necessitating some specialization among
operation and maintenance personnel. 84
Beginning as early as 1985, the U.S. House of Representatives introduced
legislation to standardize the designs available to utilities planning to build new nuclear
power plants. The Subcommittee on Energy Conservation and Power of the Committee
on Energy and Commerce heard testimony on three bills aiming to amend the Atomic
Energy Act of 1954. (See Appendix 4 for partial text of H.R 1029.) Among the main
goals: “To facilitate the development and use of standardized designs and pre-approved
sites for nuclear powerplants (sic).” 85 Utility executives, engineers from industry and

Rick Michal, “Sarver and Jordan: Maintenance at Millstone,” Nuclear News, October 2003,
pp. 40 – 48.
85

“Nuclear Powerplant (sic) Design Standardization,” Hearings before the Subcommittee on
Energy Conservation and Power of the Committee on Energy and Commerce, House of
Representatives, July 25 and December 10, 1985, Washington D.C.: U.S. Government Printing
Office, 1986, p. 40.

academia, and representatives of the Union of Concerned Scientists all agreed that design
standardization would be essential to the future of the nuclear power industry. Mr.
Bertram Wolfe, Vice President and General Manager of the General Electric Nuclear
Technology and Fuel Division, enumerated the benefits: 86
I believe that standardization offers the single most important contribution to a
more effective licensing and regulatory process and to the assurance of a high
level of safety for future nuclear power plants. There are five important reasons
why this is so . . .
First, standardization will provide the predictability which is essential to
making the multi-billion dollar decision to invest in a nuclear plant;
Second, standardization necessarily leads to a better allocation of industry
[engineering] resources and regulatory safety resources;
Third, standardization will improve the quality of NRC licensing and
regulatory decisions;
Fourth, standardization will substantially reduce the costs of constructing
and licensing new nuclear units; and
Fifth, the preapproval process, which is an integral aspect of
standardization, will enhance both the timeliness and effectiveness of public
participation in the licensing process.
Although the 1985 House bills did not get enacted, in 1989 the NRC did
implement reactor design standardization processes similar to those outlined in those
bills. 87 The NRC hoped manufacturers and designers of nuclear power plants would
submit a handful of designs for advanced certification. The designs would be for
essentially complete nuclear power plants, except for necessarily site-specific elements,
such as water intake structures. Designs would be subject to thorough safety reviews and
public hearings before receiving certification. Utilities seeking to build plants would then
choose among the certified designs and bypass design reviews during the licensing
process. That would shorten the time from application to the start of construction and
86

Ibid, pp. 143 – 144.

“Backgrounder: Nuclear Power Plant Licensing Process,” http://www.nrc.gov/reading-rm/doccollections/fact-sheets/licensing-process-bg.html, (accessed 11/1/08).

would give the utilities an added degree of certainty that, once begun, their nuclear power
plant would not need modification to meet changing NRC criteria. (Many of the reactors
built during the first wave of nuclear power plant construction were begun with designs
that were only 15 – 20 percent complete, a “design as you go” approach that added to the
duration and costs building. 88 It also resulted in custom plants at almost every site.
Unfortunately, as the United States moves toward a second wave of nuclear plant
construction, power companies and utilities have already begun selecting designs not yet
approved by the NRC or are requesting changes to the pre-certified designs. 89 Originally,
the South Texas Project Nuclear Operating Company had selected the pre-certified
General Electric/Hitachi Advanced Boiling Water Reactor (certified in 1997), but now
has chosen to partner with Toshiba to construct that type of reactor. Six construction
permit applicants aim to build a version of the Westinghouse AP1000, an advanced
passive pressurized water reactor for which the NRC just completed preliminary safety
reviews in September of 2008. Although five applicants initially favored the General
Electric/Hitachi Economic Simplified Boiling Water Reactor (design certification
application received August of 2005), Exelon and Dominion Virginia Power are
revisiting their choice. (Dominion cites an inability to reach an agreement with
GE/Hitachi over terms of the contract as the fundamental reason for the
reconsideration. 90 ) Four applicants want to build the Evolutionary Power Reactor (EPR)

“Nuclear Powerplant (sic) Design Standardization,” pp. 57 and 124.

Matthew L. Wald, “Plan to Build Reactors is Running into Hurdles,” The New York Times,
December 5, 2007, Section C, p. 1.
90

Rick Zuercher, Manager, Public Affairs, Dominion Virginia Power, Telephone Interview of
March 12, 2009.

now under construction in France, Finland, and China; the NRC received that design
application in December 2007. Finally, one application references the Mitsubishi Heavy
Industries U.S. Advanced Pressurized Water Reactor, whose design certification also was
submitted in December of 2007. (See Appendix 5 for a brief overview of reactor design
features. All design application dates have been taken from the NRC website
http://www.nrc.gov/reactors/new-reactors/col.html.) Despite the push for standardization
in the U.S., utilities and power companies have chosen both boiling water and pressurized
water reactor designs from five different manufacturers.
The manufacturers of the second wave of plants for the U.S. advertise three to
four years of construction for new plants 1154 to 1700 MW in capacity (Appendix 5).
Historical data presented earlier in this thesis indicate that larger nuclear power plants
take longer to build and that any plants with a capacity over about 1150 MW have taken
at least 3000 days from construction licensing to commencing operations (See Figure 3).
Even if construction continued for 365 days per year, past experience would suggest
plants over 1150 MW will take eight years to build, not three or four. The new EPR in
Finland was originally scheduled to begin operations in 2009 but likely will not produce
power until 2012 or later—not a very propitious sign for those awaiting ground breaking
in the U.S. 91

“Delayed Finland EPR Project Spurs Contractual Disputes,” October 22, 2008, Power:
Business and Technology for the Global Generation Industry,
http://www.powermag.com/POWERnews/1476.html, (accessed November 27, 2009).

3.2.5 New Construction Issues
In addition, as pointed out during the nuclear plant design hearings of 1985,
standardized designs do not guarantee standardized construction. 92 Each site will have its
unique topographical and geological features, weather conditions, and water supply
issues. Each construction team will have different concrete pourers, pipe fitters, welders,
electricians, and managers. Those factors will affect both how well the plant conforms to
the original design and how quickly it can be erected.
As construction ramps up worldwide, competition for building supplies will
increase. Whereas during the first round of U.S. nuclear plant construction most
suppliers were domestic, today they span the globe and outfit plants in the United States,
Asia, and Europe. 93 Areva (of France) and Northrup Grumman, Westinghouse/Toshiba
and the Shaw Group have begun building factories in Louisiana, Indiana, and Virginia,
but it will be some time before those facilities are certified by the NRC to manufacture
reactor components. 94 By some estimates, existing suppliers can fabricate enough parts
for only three or four reactors per year. 95 The demand for ultra-heavy forgings will be
especially tight--only Japan Steel works and France’s Creusot Forge (Areva) can make

“Nuclear Powerplant (sic) Design Standardization,” p. 251.

Teresa Hansen, “Nuclear Renaissance Faces Formidable Challenges,” Power Engineering, Vol.
111, Issue 8, August 2007, pp. 12 – 13; Teresa Hansen, “The Nuclear Renaissance’s Future,”
Power Engineering, Vol. 111, Issue 9, September 2007, pp. 46 – 48.
94

Matthew L. Wald, Matthew L., “After 35-Year Lull, Nuclear Power May be in the Early Stages
of a Revival,” The New York Times, October 24, 2008, p. B.3; Rebecca Smith, “Areva Will Build
Reactors in U.S.: Joint Venture with Northrop Grumman to Establish Nuclear-Components
Facility,” The Wall Street Journal, October 24, 2008, p. B.2.
95

Matthew L. Wald, “Plan to Build Reactors is Running into Hurdles,” The New York Times,
December 5, 2007, Section C, p. 1.

those elements for the new reactor designs. 96 In addition, NRC inspectors will need to
visit those foreign manufacturers to ensure component parts they make meet U.S.
regulatory requirements, adding yet another layer of complexity to parts procurement. 97
To cope with potential supply issues, some power companies and utilities have
already begun to order reactor parts, well in advance of design certifications or license
approvals. For example, Entergy Nuclear submitted an order for its forgings and turbine
components. 98 Unistar Nuclear Energy has placed orders amounting to tens of millions
of dollars on heavy steel parts for its reactor vessels and other critical components.
According to Unistar Co-CEO Michael J. Wallace, “We’re creating the certainty that the
most critical early-on hardware is in hand . . .” 99 In the end, the availability of parts may
be the determining factor in the time it takes to complete new nuclear power plants.
3.2.6 A One-Step Licensing Process
The three House bills introduced in 1985 also proposed to further decrease the
time involved and to increase the predictability of new nuclear plant construction by
allowing utilities and power companies to get early approval for potential nuclear reactor

Teresa Hansen, “Nuclear Renaissance Faces Formidable Challenges,” Power Engineering, Vol.
111, Issue 8, August 2007, pp. 12 – 13; John Carey, “Nuclear’s Tangled Economics,” Business
Week, Issue 4091, July 7, 2008, pp. 24 – 26.
97

Jeffrey S. Merrifield, “Not Your Father’s Nuclear Regulator: The Role of the Licensing
Process in the Future of Nuclear Energy,” Address to the Nuclear Energy Conference,
Washington D.C., February 16, 2005.
98

Teresa Hansen, “The Nuclear Renaissance’s Future,” Power Engineering, Vol. 111, Issue 9,
September 2007, pp. 46 – 48.

Wald, Matthew L., “Nuclear Power Venture Orders Crucial Parts for Reactor,” The New York
Times, August 4, 2006, Section C, p. 2.

sites and by replacing the two-step licensing process with a streamlined one-step
approach.
A utility seeking to build a nuclear plant today will not do so unless it
knows in advance and with certainty that it can proceed with diligent
construction and lifetime operations on a reasonable schedule . . . Three
bills currently pending in the House . . . would provide authority for the
NRC to issue combined construction and operating licenses. We believe
this is the cornerstone of a predictable licensing system.” (Mr. Sol Burnstein,
Vice Chairman, Wisconsin Electric Power Co.) 100
In 1992, Congress amended the Atomic Energy Act of 1954 to allow combined
construction and operating licenses. 101 Not surprisingly, the primary sponsors of the
earlier nuclear plant licensing bills that eventually became part of the 1992 Energy Policy
Act represented states already enjoying the benefits of electricity generated by nuclear
power and the states that are now seeking to build new nuclear power plants. (See
Appendix 6 for relevant text of the 1992 Energy Policy Act.)
Early site permitting addresses the hydrological, geological, seismic, and
meteorological features of a proposed site and how the construction of a nuclear power
plant would impact the surrounding area (especially in the event of an accident leading to
release of radiation). 102 It examines the general location of the power plant and potential

100

“Nuclear Powerplant (sic) Design Standardization,” pp. 95-96.

101

Cliffird Krauss, “Senate Votes to Simplify Nuclear-Plant Licensing,” The New York Times,
February 7, 1992, p. D2; “House Votes to Speed Licensing of Nuclear Plants,” The New York
Times, May 21, 1992, p. D2.

102

“Part 52 – Licenses, Certifications, and Approvals for Nuclear Power Plants,” U.S. NRC,
http://www.nrc.gov/reading-rm/doc-collections/cfr/part052/full-text.html, (accessed November 5,
2008). pp. 11 and 12.

alternative sites. A mandatory public hearing precedes issuance of an early site permit by
the NRC. The permit is valid for no less than 10 years and no more than 20 years. 103
An application for a combined construction and operating license (COL) must
include the technical site data plus detailed information about the complete reactor
design; safety analyses of the structures, systems, and components; emergency
evacuation plans; site security plans; quality assurance, equipment testing, and
maintenance programs. The application must also reveal particulars about the companies
contracted to build the facility, the plant organization structure, and training and
requalification programs for reactor operators. 104 Up front review of all of these aspects
should minimize the likelihood of delays such as those that plagued Texas Utility
Company’s Comanche Peak and others. 105 In addition, a mandatory public hearing
follows receipt of the application, giving the local people as well as organized groups a
chance to voice their concerns. As the industry demanded, once the NRC issues the
COL, it may not “modify, add, or delete any term or condition of the combined license,
the design of the facility, the inspections, tests, analyses, and acceptance criteria
contained in the license” (unless of course a significant safety issue comes to light during
construction). 106

103

“Nuclear Power Plant Licensing Process,” U.S. NRC Backgrounder, Washington D.C.: U.S.
NRC Office of Public Affairs, July 2005.

104

Part 52—Licenses, Certifications, and Approvals for Nuclear Power Plants”, pp. 23 – 29; C. J.
Fong, Nuclear Regulatory Commission Region II Construction Inspection Organization,
Telephone Interview of May 14, 2009; Hossein Hamzehee, Nuclear Regulatory Commission,
Telephone Interview of May 14, 2009.

105

106

Hossein Hamzehee, Nuclear Regulatory Commission, Telephone Interview of May 14, 2009.
Part 52—Licenses, Certifications, and Approvals for Nuclear Power Plants,” pp. 23 – 29.

At the outset of construction of the new reactor facility, the applicant (now
licensee) must submit to the NRC a schedule of its “Inspections, Test, Analyses, and
Acceptance Criteria” (ITAAC) and must notify the NRC upon completion of the various
elements of that schedule. If the Commission finds that the criteria have been met, a date
for fuel loading can be set. At that time there is one last opportunity for a public hearing,
but only if there is evidence that one or more of the criteria has not been or cannot be
met. Barring any fact-based opposition, the NRC then considers the nuclear power plant
licensed for operation.
The NRC envisioned an orderly three-step process in which reactor manufacturers
would receive design certifications, utility and power companies would get early site
permits, and finally, those companies would apply to build and operate a nuclear power
plant. 107 In reality, as outlined above, design certifications are being submitted in parallel
with COLs. Companies hoping to build on existing nuclear power plant sites have
chosen to roll the site permitting into their license applications rather than procure a
separate early site permit. Thus, as of October 2009, only four of the 17 COL applicants
also had submitted early site permits: Exelon (for its Clinton, IL site), System Energy
Resources Inc., (for Grand Gulf, MS), Dominion Nuclear (for North Anna, VA) and
Southern Nuclear Operating Company (for Vogtle, GA). 108 The NRC also expected to
receive one lead construction and licensing application, to test the new process, followed

107

Richard Meserve, and Ernest Moniz, “The Changing Climate for Nuclear Power in the United
States,” Bulletin of the American Academy of Arts and Sciences, Vol. 55, No. 2, Winter 2002, pp.
57 – 72.

108

“Early Site Permit Applications for New Reactors,” http://www.nrc.gov/reactors/newreactors/esp.html, (accessed October 20, 2009).

by others a few years later. 109 Instead, they found themselves deluged with seventeen
COLs in the fourteen months between mid-July 2007 and mid-October 2008. 110
How long will it take to review and accept each application? Although the NRC
has claimed it would take about 42 months under its new system, some nonpartisan
groups, such as the Congressional Research Service, take a gloomier view and predict
that it could take 15 years to complete the process! 111
Unlike the previous round of nuclear power plant construction permit applications
during which each individual utility developed its own submission, many of the current
applications were created by one company: NuStart Energy Development. NuStart was
established in 2004 by ten power companies and two reactor vendors for the purpose of
gathering the requisite materials, completing the necessary design engineering, and
composing COL applications. 112 The group wanted to demonstrate the viability of the
new licensing process. NuStart aimed to provide a forum for the open exchange of ideas
and information among the power companies, vendors, and the NRC. Building on the
concept of design standardization, NuStart also has attempted to standardize the many
parts of the COL application, including descriptions of reactors, mechanical systems, and

109

Marilyn Kray, “New Reactor Licensing: Matching Expectations and Reality,” Regulatory
Information Conference (RIC) 2008: Enhancing Safety During the Global Nuclear Renaissance,
March 13, 2008.

110

“Combined License Applications for New Reactors,” http://www.nrc.gov/reactors/newreactors/col.html, (accessed November 2, 2008).
111

Janet Elliott, and Tom Fowler, “Deregulation Debate: Second of Two Parts, Market Fix Rests
on Bright Ideas,” Houston Chronicle, October 8, 2007, www.chron.com, (accessed 10/29/08).

112

www.nustartenergy.com, (accessed May 24, 2008); “NuStart,” http://www.entergynuclear.com/new_nuclear/nustart.aspx, last accessed 5/24/2008.

components. 113 It has created a baseline COL application that can be used as a template
by a variety of power companies and utilities. As a testament to its success, NuStart has
been a partner in the COL applications for Entergy’s Grand Gulf, MS and River Bend,
LA sites, the Tennessee Valley Authority’s Bellefonte, AL site, and Progress Energy’s
Harris, NC and Levy County, FL sites, among others. 114
Following the NuStart lead, Constellation Energy joined with Areva NP (a reactor
manufacturer) and Electricite de France (EdF, the French electric utility company) to
form Unistar Nuclear LLC in 2007 to bring the Areva Evolutionary Power Reactor to the
U.S. 115 The Unistar business model would cut the risk to any individual investor by
building many identical reactors, taking advantage of economies of scale. 116 The venture
also capitalizes on the multinational experience of Areva. Likewise, Toshiba (maker of
advanced boiling water reactors) and NRG Energy have partnered to build new reactors
at NRG’s South Texas Project site and then to market, develop, and invest in other
reactors around the U.S. 117

113

Marilyn Kray, “New Reactor Licensing: Matching Expectations and Reality,” Regulatory
Information Conference (RIC) 2008: Enhancing Safety During the Global Nuclear Renaissance,
March 13, 2008; “Consortium Provides Forum for Standard Plant Design and Licensing,”
February 27, 2008, www.nustartenergy.com/DisplayArticle.aspx?ID=20080227-1, (accessed May
24, 2008).
114

“NuStart Energy Development,” www.sourcewatch.org/index.php?title-NuStart_Consortium,
(accessed May 24, 2008); “NuStart Energy Development: Combined Construction and Operating
License,” www.citizen.org/cnep/energy_enviro_nuclear/newnukes/articles.cfm?ID=14161,
(accessed May 24, 2008).
115

“NuStart Successes Prompt Membership Changes,” November 6, 2007,
www.nustartenergy.com/DisplayArticle.aspx?ID=20071024-1, (accessed May 24, 2008).

116

Matthew L. Wald, “Partnership Formed to Build Nuclear Plants,” The New York Times,
September 16, 2005, Section C, p. 4.

117

Matthew L. Wald, “NRG Energy Sets Up an Entity to Build Nuclear Plants,” The New York
Times, March 26, 2008, Section C, p. 2.

3.2.7 Environmentally Sound Energy
Deregulation, design standardization, and changes in the licensing process were
not the only factors contributing to the renewed interest in nuclear power for electrical
generation. In the 1960s and 1970s Americans focused on getting rid of air and water
pollution; in the 1990s and 2000s, the contribution of “greenhouse gases” to global
climate change grabbed their attention. Emissions from fossil fuel burning power
generation facilities, particularly carbon dioxide, which can easily trap heat, have been
implicated in the changes in global temperatures and precipitation patterns, and the
increased severity of storms and droughts. 118 Over 180 nations have ratified the Kyoto
Protocol since it was adopted in 1997 in an international attempt to reduce emissions of
greenhouse gases. And, because nuclear power plants emit almost no carbon dioxide
during their operation, many of those countries have renewed their interest in nuclear
power. 119 “There is a growing recognition that if we are going to meet our future need
for electric energy and also reduce our emissions of greenhouse gases . . . we simply must
build the next generation of advanced nuclear energy plants.” 120
Although the U.S. did not sign the Kyoto Protocol, groups of states on the west
and east coasts have banded together to implement carbon dioxide (CO2) emission
118

W. J. Nutall, Nuclear Renaissance: Technologies and Policies for the Future of Nuclear
Power, London, England: Taylor and Francis, 2004; “Kyoto Protocol,”
http://unfcc.int/kyoto_protocol/items/2830.php, (accessed June 23, 2008).

119

Although nuclear power plants emit almost no carbon dioxide during their operation, when the
entire life cycle of is considered (mining through electric production), nuclear power does
contribute greenhouse gases to the atmosphere. See, for example, Jef Beerten et al., “Greenhouse
Gas Emissions in the Nuclear Life Cycle: A Balanced Appraisal,” Energy Policy, 37, 2009, pp,
5056 – 5068.

120

“Thirst for Energy Leads U.S. Down Old Path: Nuclear Power,”
www.usatoday.com/tech/news/2005-06-12-nuclear-resurgence_x.htm, (accessed May 24, 2008).

reduction programs. The West Coast Governor’s Global Warming Initiative focused on
increased use of renewable energy sources and increased efficiency of all products,
especially automobiles. 121 On the opposite coast, the Regional Greenhouse Gas Initiative
(RGGI) has implemented a “cap and trade” program to limit and reduce CO2 emissions
from electric power plants (“RGGI Inc.”). 122 Each of the ten participating states
(Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey,
New York, Rhode Island, and Vermont) is working to establish a total number of CO2
allowances for its electric generating plants (the “cap”). Facilities using less than their
allowance would be able to auction them off in a regional auction to those needing extra
allowances (the “trade”). Companies or utilities with nuclear plants in their portfolios
would be allowed to transfer allowances to bigger polluters, such as coal fired plants, or
to sell them at auction for a profit. Those profits could then be used to invest in other
technologies with low emissions.
A carbon tax system also aims to reduce CO2 emissions. Such a system would
tax each ton of carbon emitted by any type of electric generating plant, any industry, and
any vehicle. 123 Owners of low carbon nuclear, wind, or solar power plants would benefit
by paying little or no carbon tax. The tax would provide an incentive for companies to

121

“West Coast Governor’s Global Warming Initiative,” http://www.ef.org/westcoastclimate/,
(accessed January 9. 2009).

122

“RGGI Inc.” www.rggi.org/rggi, (accessed January 9, 2009).

123

Juliet Eilperin, and Steven Mufson, “Tax on Carbon Emissions Gains Support: Industry and
Experts Promote it as Alternative to Help Curb Greenhouse Gases,” April 1, 2007,
www.washingtonpost.com, (accessed January 9, 2009); Timothy Gardner, “Carbon Tax Seen as
Best Way to Slow Global Warming,” October 9, 2008, www.reuters.com, (accessed January 9,
2009).

forego investment in carbon emitting technologies in favor of those “cleaner”
alternatives.
Carbon taxes and cap and trade were not included in its energy policy when the
Bush/Cheney administration took office in 2001. However the administration did offer a
plan for “dependable, affordable, and environmentally sound energy”, a plan that
promoted not only increased oil and natural gas exploration but also expansion of
domestic renewable energy sources and nuclear energy. 124 With regards to nuclear
power in particular, the Report of the National Energy Policy Group of May 2001 asked
the President to support “the expansion of nuclear energy as a major component of our
national energy policy.” 125 The report, National Energy Policy: Reliable, Affordable,
and Environmentally Sound Energy for America’s Future, often called the “Cheney
Report”, asked the Department of Energy (DOE) to address the potential for nuclear
power to improve air quality. It encouraged the NRC to ensure that safety and
environmental protection were considered with high priority as it “prepared to evaluate
and expedite applications for new advanced-technology reactors.” 126 The Policy also
recommended the extension of the Price-Anderson Act of 1957. In short, the National
Energy Policy of 2001 set the stage for the pro-nuclear governmental activity and
legislation that followed.

124

125

Ibid, p. 5-21.

126

Ibid, p. 5-21.

A Roadmap to Deploy Nuclear Power Plants in the United States by 2010
(commonly referred to as “Nuclear Power 2010”) was released in October 2001. The
document, prepared by the members of industry and of the Department of Energy
expanded on ideas set forth in the National Energy Policy. 127 It outlined the steps
necessary for new nuclear plants to be operational by 2010. Among the conclusions:
1. The electricity generated by new nuclear power plants would have to be
economically competitive for them to remain a viable option, (“Investors are
going to want to have confidence, if they look at financing a competitive
generation asset, that that asset is going to be able to earn a reasonable return in
the market in which they have to operate in” James K. Asselstine, Managing
Director, Lehman Brothers Inc., during testimony before the Committee on
Energy and Natural Resources of the U.S. Senate, “Nuclear Power Industry,” p.
44),
2. The regulatory process for siting and licensing new plants would need to be
proven timely, efficient and appropriate to the task at hand,
3. Utilities and power companies would need to order new plants by the end
of 2003 to have them operational by 2010,
4. The most advanced new reactor designs would not be available but those
derived from existing reactors (such as those outlined in Appendix 5) could
be deployed by 2010, and
5. Although the decision to build a new nuclear power plant must be market
driven and supported by private investment, government support (in terms
of legislative support as well as cost sharing programs) would be essential. 128
“Nuclear Power 2010” recommended that the DOE investigate financial incentives (such
as tax credits, tax exempt financing, and power purchase agreements) to motivate design

127

128

“Nuclear Power 2010,” Vol. 1, p. vi.

and construction projects. 129 It also put into place a 50-50 cost sharing program to help
the first movers demonstrate the NRC’s revised site permitting and reactor licensing
procedures. The object of this aspect of “Nuclear Power 2010” was to help the NRC
identify and resolve issues in those procedures before the industry had committed too
much of its own resources to new nuclear power plant construction. 130 Exelon took
advantage of the program for an early site permit for its new Clinton site, as did System
Energy Resources for Grand Gulf, and Dominion Nuclear for North Anna. 131 And, in
2005, NuStart received $260 million under the cost sharing program to complete the
design and engineering work for COL applications for new reactors at Bellefonte and
Grand Gulf. 132
3.2.8 The Energy Policy Act of 2005
Years of Congressional hearings about the role of nuclear power in the energy
future of the U.S. preceded the passage of the Energy Policy Act of 2005 (EPAct). As a
result, according to Keith Martin, Partner, Chadbourne & Parke, “[F]or the first time,
both Congress and the President are on record nuclear is one of the things we need to

129

Ibid, p. 46.

130

“Nuclear Power 2010 Program,” Hearing Before the Committee on Energy and Natural
Resources of the United States Senate, April 26, 2005, Washington D.C.: U.S. Government
Printing Office, 2005, p. 31.
131

“Combined License Applications for New Reactors,” http://www.nrc.gov/reactors/newreactors/col.html, (accessed November 2, 2008).
132

“NuStart Energy Development: Combined Construction and Operating License,”
www.citizen.org/cnep/energy_enviro_nuclear/newnukes/articles.cfm?ID=14161, (accessed May
24, 2008).

pursue as a country.” 133 In an effort to induce companies to pursue investment in nuclear
power plants, EPAct established a production tax credit of 1.8 cents per kWh of
electricity produced for the first 6000 MW (not MWh) of power produced each year
(Holt). To get the tax credit, utilities and power companies would need to file their COL
by the end of 2008 and begin construction before 2014. 134
EPAct renewed the Price-Anderson Indemnity Act of 1957 and extended its
expiration date to December 31, 2025. 135 Nuclear power plant operators now must obtain
$300 million per plant in liability insurance from a private insurer and contribute another
$10 million annually to the industry pool. As a result of those annual contributions, the
total industry liability for a nuclear accident now stands at about $10 billion. 136
EPAct also created a “delay risk insurance” policy for the power companies and
utilities. 137 Many of the delays and cost overruns of the first round of nuclear plant
construction have been attributed to changing regulations and to lawsuits brought by
nuclear opponents. To mitigate the impact of those types of problems in the future, the
EPAct authorizes the DOE to cover some of the cost of delays due to regulatory issues or

133

Gerelyn Terzo, “A Nuclear Renaissance? The Divisive Energy has Drawn Increased Interest,
but its New Day Hasn’t Yet Arrived,” The Investment Dealers’ Digest, December 4, 2006, p. 1.

134

Terzo; “Implementation of the Provisions of the Energy Policy Act of 2005,” Hearings Before
the Committee on Energy and Natural Resources of the United States Senate, May 15, 2006, May
22, 2006, June 12, 2006, June 9, 2006, Washington D.C.: U.S. Government Printing Office,
2006.

135

“The Price-Anderson Act: Background Information,” American Nuclear Society, November
2005, www.ans.org, (accessed July 2, 2008).

136

“Insurance Coverage Key to Nuclear Expansion Plans,” June 30, 2008, http://0premium.hoovers.com.cals.evergreen.edu/subscribe/co/news/detail.xhtml, (accessed July 8,
2008).
137

Terzo.

litigation coming outside of the established licensing process. 138 In 2007, the DOE
announced it would insure the first two new nuclear power plants against delays for an
amount up to $500 million each and the subsequent four plants up to $250 million
each. 139
The final incentives for the nuclear industry outlined in the Energy Policy Act of
2005 were not finalized until October of 2007: Loan guarantees. Loan guarantees help
power companies deal with the high up front capital costs of constructing new nuclear
facilities. They assure the lenders that the government will pay back the loans if the
borrowers (the power companies) default, reducing the risk to the lenders and increasing
their willingness to provide the needed funds. Financial industry experts had convinced
Congress that without loan guarantees, banks and Wall Street investors would not support
a new round of reactor construction.
Wall Street’s position may have resulted from the 1983 default on over $2.5
billion in nuclear power plant construction revenue bonds by the Washington Public
Power Supply System (WPPSS). WPPSS had undertaken an ambitious program to build
five new nuclear power plants in Washington State, but management problems, schedule
delays, and cost overruns plagued the projects. 140 WPPSS originally quoted a cost
138

“Implementation of the Provisions of the Energy Policy Act of 2005,” p. 53.

139

“Howard Baker Center for Public Policy Nuclear Power Conference, Remarks as Prepared for
Secretary Bodman,” U.S. Department of Energy, Office of Public Affairs, October 4, 2007,
http://www.energy.gov/print/5571.htm, (accessed July 7, 2008).
140

“Causes of Cost Overruns and Schedule Delays on the Five WPPSS Nuclear Power Plants,”
Report to the Washington Sate Senate and 47th Legislature of the Washington State Senate
Energy and Utilities Committee, WPPSS Inquiry, Vol. 1, January 12, 1981; D. Victor Anderson,
Illusions of Power: A History of the Washington Public Power Supply System, New York:
Praeger, 1985; James Leigland, and Robert Lamb, WPP$$: Who is to Blame for the WPPSS
Disaster, Cambridge, MA: Ballinger Publishing Co., 1986.

between $4.1 billion and $6.6 billion for all five plants, but by 1983 had revised that
estimate, saying it would take about $17.3 billion to complete the projects. 141 When the
Washington Sate Supreme Court voided its contracts with local utilities for two of the
nuclear plants, WPPSS could pay neither the interest nor the principal on some of its
bonds, and defaulted. 142 In the end, WPPSS completed only one of the five plants--the
Columbia Generating Station. 143
Thus, for the next round of nuclear power plant construction, the DOE can
guarantee up to 100 percent of a loan but in an amount not to exceed 80 percent of the
total cost of the project. 144 And, in a departure from past loan guarantee programs, the
volume of loan guarantees sought per year would not be capped—the DOE can approve
as many as it deems necessary. 145 The government and not the project financers will be
ultimately responsible if a utility defaults on the loan. Unfortunately, the companies that
have submitted applications are seeking $122 billion in loan guarantees, far exceeding the
$18.5 billion allocated. 146

141

“Causes of Cost Overruns and Schedule Delays on the Five WPPSS Nuclear Power Plants.”

142

Anderson, pp. 132 – 133.

143

Ibid, p. 138.

144

Edmund L. Andrews and Matthew L. Wald, “Energy Bill Aids Expansion of Atomic Power,”
The New York Times, July 31, 2007.

146

“DOE Announces Loan Guarantee Applications for Nuclear Power Plant Construction,” Press
Release of the United States Department of Energy, Office of Public Affairs,
http://www.lgprogram.energy.gov/press/100208.pdf, (accessed May 4, 2009).

Those who do not receive funds under the EPAct loan guarantee program may
have access to additional backing. The Senate’s Clean Energy Jobs and American Power
Act (S. 1733), introduced in September 2009 by Senators John Kerry and Barbara Boxer,
includes new provisions for investment tax credits, $18.5 billion or more in additional
loan guarantees, and federally financed training for nuclear workers. 147 According to
Senator Lindsey Graham of South Carolina, a strong proponent of the bill, “America’s
turned the corner on nuclear power.” 148
3.2.9 Addressing Nuclear Power Plant Safety
Changes in the licensing process and generous funding packages will reduce
licensing and financial uncertainty associated with new nuclear power plant construction.
Another contextual element that has changed since the 1960s and 1970s that could affect
new construction is the way in which the NRC approaches nuclear power plant safety. In
the early years of the industry, the NRC relied on “defense in depth”, multiple layers of
protective devices and processes, backup power supplies and emergency response
systems incorporated into a power plant design. 149 Such redundancy of systems and
ample safety margins were expected to prevent accidents or to protect the health and

147

“Can We Afford More Subsidies for Nuclear Power?” Union of Concerned Scientists, October
20, 2009, http://www.ucsusa.org/news/press_release/can-we-afford-more-subsidies-0296.html,
(accessed November 2, 2009); “111th Congress, 1st Session, S. 1733,” The Clean Energy Jobs
and American Power Act, September 30, 2009,
http://www.govtrack.us/congress/billtext.xpd?bill=s111-1733, (accessed November 2, 2009).

148

Steven Mufson, “A Nuclear Power Boost for Bill,” The Washington Post, October 28, 2009,
http://www.washingtonpost.com/wp-dyn/content/article/2009/10/27/AR2009102704081-pf.html,
(accessed November 2, 2009).
149

Perin, p. 6.

safety of the public in the unlikely event that an accident did occur. 150 Likewise, the
NRC took a “defense in depth” approach to safety regulation, developing rules to cover
just about every conceivable situation, and updating the rules as new situations arose. In
the 1970s, the NRC began adopting and refining a new approach to complement defense
in depth: Probabilistic risk assessment and risk informed regulation.
Probabilistic risk assessment (PRA) examines the parts of a complex system and
factors related to them that could affect safety. 151 It looks at the potential hazard or
failure to be avoided (such as a valve leakage, a power outage, or a core meltdown), then
backtracks to understand the multitude of “initiating events” that might lead to that
hazard. It also examines the possible sequences of events between the initiating event
and the failure. PRA then assigns estimated frequencies to each step along the way and
for each entire pathway. In this way, PRA gives the NRC (and the industry) an idea of
the relative risks associated with potential hazards or failures for a nuclear power plant.
Both can use that information to isolate areas of concern as well as areas that no longer
need strict attention or regulation. 152 (See Appendix 8 for more information about PRA.)
PRA and the associated use of computer modeling have allowed analysts to
quantify risks of operating nuclear power plants and to pinpoint weaknesses in new
reactor designs. Unfortunately, PRA cannot account for all human elements (errors in
judgment, procedural mistakes, and the like), modifications to equipment not reflected in

150

Meserve.

151

“Fact Sheet on Probabilistic Risk Assessment,” The Nuclear Regulatory Commission,
http://www.nrc.gov/reading-rm/doc-collections/fact-sheets/probabilistic-risk-asses.html; Rick
Grantom, The South Texas Project, Telephone Interviews, Spring 2009.
152

Meserve; “Fact Sheet on Probabilistic Risk Assessment;” Grantom.

design documents, or quirks in a system. 153 Some experts argue that it should only be
used retrospectively, since forward-looking estimates of risk (or those associated with
new designs) must be based on best guesses and not actual data. 154 In either case, there
will always be a degree of uncertainty associated with the PRA risk estimates.
By the middle of the 2000s, the time was ripe for a “nuclear renaissance.” Oil and
natural gas prices had jumped to record highs. (Figures 6 to 8.) Although coal remained
relatively inexpensive, increased reliance on coal raised concerns about greenhouse gas
emissions. The industry itself was demonstrating that the older nuclear plants could be
operated safely and economically as capacity factors increased and the number of
unplanned shutdowns dropped (Figures 4 and 5). The NRC had revamped its licensing
process and the U.S. government showed its support for new nuclear power plant
construction by providing financial incentives in the form of production tax credits and
loan guarantees. Utilities and consortia submitted combined construction and operating
licenses for new nuclear power plants. But it will be a few more years before we know if
anyone actually builds a facility, if the “renaissance” has in fact begun.

153

Grantom; Perin, p. xi – xiii.

154

Rodney P. Carlisle, “Probabilistic Risk Assessment in Nuclear Reactors: Engineering
Success, Public Relations Failure,” Technology and Culture, Vol. 38, No. 4 (October 1997), pp.
920 – 941.

3.3: More Information About Federal Loan Guarantees
Parts 3.1 and 3.2 briefly reviewed the environmental and regulatory context of
nuclear reactor construction in the United States during the 1960s, 1970s and today.
Table 2 below summarizes some of the major differences between the state of the nuclear
industry during the original round of reactor construction in the United States and that of
the current “renaissance.”

Table 2: The State of the Nuclear Industry, Then and Now: A Comparison of
Factors Affecting the Industry in the 1960s – 1980s and in the 2000s

Table 2 reveals that while the U.S. electric generation industry faced energy
supply issues and concerns over air quality both during the first round of reactor
construction and today, much else has changed. That leads to the question “Which of the
changes actually has spurred the recent spate of investment and applications for licenses
to build new nuclear reactors in the United States?” What provoked utilities to finally

say “Let’s do it!”? And, why now? For decades politicians have aspired to wean the
country from its dependence on foreign oil and environmentalists have voiced concerns
about the environmental degradation caused by a reliance on coal. But those factors
alone did not spur a renewed interest in nuclear power, nor did the codification of safety
standards or the NRC certification of new reactor designs. Regional initiatives to curb
greenhouse gases even failed to spur reactor construction in those areas. The historical
review presented in this thesis suggests that the federal loan guarantees promised by the
Department of Energy as part of the Energy Policy Act of 2005 served as the catalyst for
the nuclear renaissance.
Timing provides one clue as to the importance of the loan guarantees. The NRC
revised its license application procedures and started calling for standard reactor designs
to review in the 1990s, yet those actions did not spur any construction and operating
license applications. The electric industry began deregulating in the mid 1990s. Some
states moved early to open their markets to competition; others remain regulated today.
However, as seen earlier, whether a state is (or was) regulated or competitive had little
impact on a utility’s decision to consider building a new nuclear power plant. Finally,
while Nuclear Power 2010 did spur the formation of consortia, and the risk insurance and
tax credits of the Energy Policy Act of 2005 did provide some financial incentives, the
NRC received no license applications until most of the details of the loan guarantee
program were in place in late 2007. (Recall that the first complete application came from
NRG Energy in September 2007, for its third and fourth reactors at its South Texas
Project.)

As early as March of 2004, the Senate Committee on Energy and Natural
Resources heard statements indicating that federal financial support would be necessary
to spur investment in new nuclear plants. Marvin S. Fertel, Senior Vice President and
Chief Nuclear Officer of the Nuclear Energy Institute (a policy organization of the
nuclear energy and technologies industry) reported that “[t]he financial community has
indicated that it is unlikely to provide external debt financing from the capital markets,
given the regulatory risks associated with the first several new nuclear power plants.
This means that companies considering building new nuclear power plants must either
finance the first few plants with 100 percent equity, or obtain government loans, loan
guarantees, or some other form of comparable government insurance . . .” 155
James K. Asselstine, Managing Director of Lehman Brothers, Inc., research
analyst responsible for covering the electric utility and power sector, and member of the
Secretary of Energy Advisory Board’s Nuclear Energy Task Force, testified before that
same Senate Committee regarding its Nuclear Power 2010 Program on April 26, 2005.
(Recall that Nuclear Power 2010 involved a cost sharing program designed to identify
sites for new nuclear power plants, bring new reactor technology to market, and
demonstrate the new NRC licensing process.) He commented that one of the two key
questions of interest to analysts and potential investors would be “Is the proposed new
nuclear plant cost competitive with other available alternatives for new baseload
generating capacity? 156 The first three to four plants of each design likely would not be

155

“Nuclear Power in the United States,” Hearing Before the Subcommittee on Energy of the
Committee on Energy and Natural Resources of the United States Senate, March 4, 2004,
Washington D.C.: U.S. Government Printing Office, 2004, p. 29.

156

“Nuclear Power 2010 Program,” p. 5.

competitive, due in part to the first-of-a-kind-engineering costs incurred to sufficiently
complete a new reactor design for NRC regulatory approval. The Energy Advisory
Board’s Task Force had concluded that some federal government financial incentives
would be needed to ensure cost competitiveness and to mitigate the commissioning risks
associated with the initial group of new nuclear plants. At that time, [t]he Task Force
recommended the following financial incentives: a Federal loan guarantee or direct
government loans; a Federal power purchase agreement; accelerated depreciation; an
investment tax credit; and a production tax credit.” 157
Later testimony before the Department of Energy (DOE) and its Chief Financial
Officer in June 2007 provides further clues as to the importance of loan guarantees to the
nuclear power industry. 158 The loan guarantee program already had been approved by
Congress. Still, high level executives from energy companies made their way to Capitol
Hill to stress the need for the government to show its support for nuclear power in that
material way. For example, Steve Winn, Executive Vice President for NRG Energy
remarked
NRG believes the coming wave of nuclear plants in the U.S. will require
the commitment of developers like NRG, equipment suppliers, and state
and local governments, and we believe that all of the parties have tangibly
shown their commitment . . . The remaining piece in the future success of
nuclear is a strong commitment on the part of the Federal government . . .
providing the capital necessary for a nuclear resurgence, can only be
accomplished by using the DOE Loan Guarantee Program . . .”). 159

157

Ibid, p. 7.

158

“LPG Public Meeting,” U.S. Department of Energy, Office of the Chief Financial Officer,
Washington D.C.: Executive Court Reporters, Inc., June 15, 2007.

159

Ibid, pp. 9 – 11.

Paul Hinnenkamp of Entergy Nuclear echoed those sentiments, claiming that “loan
guarantees are essential to reduce the financial risk of new nuclear deployment and
enable Entergy to leverage the large investment required . . . We cannot take on the debt
required to finance a new build without an effective loan guarantee program.” 160 Jeff
Lyash, President of Progress Energy Florida, also emphasized the need for the loan
guarantee program as a way to “send a strong, clear signal that the federal government
supports commercial nuclear operations as a part of our solution [to meeting growing
energy needs in a way that’s environmentally responsible].” 161
The DOE also accepted written statements about the loan guarantee program
through July 2 of that summer. The documents received reminded the DOE of the
magnitude of investment required to build a nuclear plant. Michael J. Wallace, President
of Constellation Generation Group, advised:
. . . the production tax credits contained in the Energy Policy Act are
necessary to incentivize early movers who may otherwise be reluctant
to be the first to market.
But the most important Energy Policy Act incentive for new nuclear
is the Title XVII loan guarantee program, which we view as indispensable.
The loan guarantees are meant to address a market financing gap that results
from the combination of several factors including (i) the prior nuclear plant
construction cycle that . . .was burdened by regulatory uncertainty and
resulting delays and cost over-runs, (ii) perceived uncertainty of an untested . . .
regulatory system, (iii) perceived technology risk, and (iv) an institutional
loss of understanding regarding the reality of nuclear financial risk in some
elements of the financial community. 162

160

Ibid, p. 57.

161

Ibid, p. 133.

162

Michael J. Wallace, “On the Notice of Proposed Rulemaking Implementing the Loan
Guarantee Program for Projects that Employ Innovative Technologies,” Jun15, 2007,
http://www.lgprogram.energy.gov/nopr-comments/comment03.pdf, (accessed March 19, 2009).

Executives from Constellation Energy Group, Inc., Entergy Corp., and Exelon submitted
a joint statement that outlined the millions of dollars and years of effort already
committed by the companies interested in applying for combined construction and
operating licenses.
The size and scale of nuclear projects, and the multi-year commitments
that need to be made by private industry, make it imperative that DOE
create certainty in the near-term around the future availability of the Title
XVII Loan Guarantee Program for nuclear power projects . . . the multiyear commitment being made by private parties needs to be matched with
a multi-year commitment from the federal government. 163
Likewise, a statement released by Dominion Resources, a company in the process of
developing its application for a new reactor at its North Anna site, claimed that “through
all of its planning and preparation, Dominion has understood the economic reality that a
federal loan guarantee is essential to raise the capital necessary to build this plant.” 164
“Essential.” “Most Important.” “Imperative.” Whether in oral or written
testimony to the DOE, these industry representatives (and others) expressed their
conviction that without the financial backing of the U.S. government, the nuclear
renaissance would not occur.
Similar sentiments surfaced in the media and in interviews conducted expressly
for this thesis, to explore the reasons companies had submitted applications to build new
nuclear power plants. When asked about the role of loan guarantees in the future of new

163

Joe C. Turnage, Theodore Bunting Jr., John F. Young, and Steve Winn, “Written Comments in
Response to RIN 1901-AB21, Loan Guarantees for Projects that Employ Innovative
Technologies, 72 Federal Register 27471 (May 16, 2007),” July 2, 2007,
http://www.lgprogram.energy.gov/nopr-comments/comment41.pdf, (accessed March 19, 2009).

164

“Comments of Dominion Resources Inc. on DOE Notice of Proposed Rulemaking 10 CFR
Part 609, RIN 1901 – AB21,” July 2, 2007, http://www.lgprogram.energy.gov/noprcomments/comment36.pdf, (accessed March 19, 2009).

nuclear power plant construction in the United States, Richard Zuercher of Dominion,
Danny Blanton, Entergy Nuclear, and a spokesperson for PPL Corp. of Pennsylvania all
agreed on their importance. For PPL, the guarantees “are a necessary component for
getting financing at reasonable rates. They are a big part of the decision.” 165 PPL CEO
James Miller explained that federal loan guarantees were needed because Wall Street
probably would not loan the money without them. 166 According to Dominion’s
Zuercher, “They serve as handholding for investors, if you fail. But you hope you never
have to draw on them.” 167 He felt that Dominion was ‘well positioned’ to receive a
guarantee. Entergy’s Blanton tempered his expectations, recalling that getting a loan
guarantee required a company to have its NRC license approval in hand—and such an
approval is still years out for all applicants.
In addition, politicians like Washington State’s Senator Maria Cantwell, member
of the Senate Commerce, Energy, Finance, and Natural Resources Committees, supports
the expansion of nuclear power as part of a plan to make the United States’ energy
system “cleaner, more efficient, and more diverse.” 168 Ms. Cantwell has recommended
financial backing for investment in wind and solar technologies and upgrades in the
electric grid, tax credits for plug-in electric vehicles, and the loan guarantees for new

165

Anonymous, PPL, Telephone Interview of February 26, 2009.

166

“PPL CEO Sees More Fast Growth in Merchant Unit,” March 25, 2008,
http://www.reuters.com/article/companyNews/idUSN25299610120080325, (accessed March 25,
2009).
167

Rick Zuercher, Manager, Public Affairs, Dominion Virginia Power, Telephone Interview of
March 12, 2009.
168

Maria Cantwell, United States Senator, Personal Correspondence of July 15, 2009.

nuclear power plants: “I continue working with my colleagues to further develop
balanced and sustainable solutions to our nation’s long term energy needs.” 169
Somewhat surprisingly, however, Progress Energy Florida withdrew from the
loan guarantee competition, but continues to press forward to build its Levy County,
Florida plant. According to Rick Kimble, Manager of Nuclear Communications, that
decision rested on the high cost of applying and the provision contained in the guarantees
giving the DOE possession of the power plant if a company defaulted on its loan. 170
Progress Energy did not want the DOE to take over their nuclear facility (EPAct of 2005
designates the DOE as the primary project manager in the event of a default 171 ), nor did
they have faith in the DOE’s ability to carry out the loan guarantee program as intended.
The Tennessee Valley Authority (TVA) also has moved ahead with its plans for
new nuclear without loan guarantees. Because the TVA is a federal agency, it may not
qualify. Furthermore, it has been sitting on its own unused nuclear assets since the mid1980s, when it shuttered several partially complete nuclear units. TVA updated then
reopened Browns Ferry Unit 1 in 2007, more than 30 years after fire damage shut it down
in 1975, and 20 years after all other Browns Ferry units closed in 1985 due to safety and
management concerns. Also in 2007, the TVA Board of Directors approved the spending

169

Ibid.

170

Rick Kimble, Manager of Nuclear Communications, Progress Energy Florida, Telephone
Interview of January 29, 2009.

171

“Loan Guarantee Provisions in the 2007 Energy Bills: Does Nuclear Power Pose Significant
Taxpayer Risk and Liability?” Environmental and Energy Study Institute Briefing, October 30,
2007, Washington D.C., http://www.eesi.org/103007_Nuclear_Loan_Guarantee_Briefing,
(accessed December 15, 2009).

of $2.5 billion over five years to complete Watts Bar 2. The proposed new nuclear units
for TVA will be built on another site with partially complete reactors, in Bellefonte, AL.
Thus, while industry analysts and many utilities deem loan guarantees crucial to
the future of new nuclear power plant construction, some companies are proceeding
without them. Why? What is the rationale for their multi-billion dollar investments?
The sections that follow examine in more detail the reasons expressed, in the media and
in phone interviews, by many of the companies that have submitted applications to build
new nuclear plants. They review what the companies themselves reveal about the driving
force(s) behind the nuclear renaissance in the United States.

4.0 What the Electric Companies and Utility Owners Tell Us
The Nuclear Regulatory Commission’s list of COL applicants served as the basis
for finding interview candidates for this research. Although phone calls to company
executives were not returned, calls to the media/press and operating departments did
result in interviews with representatives from 8 of the 18 applicant companies:
AmerenUE, Dominion, Duke Energy, Entergy, NRG Energy (South Texas Project), PPL,
Progress Energy Florida, and the Tennessee Valley Authority (TVA). The sample may
suffer from a voluntary response bias. However, the nuclear facilities owned by these
companies do cover a wide geographical area: from Texas to South Carolina and Florida
to Maryland. The sample also includes companies operating in both regulated and
deregulated states, as well as private entities, public utilities, and a federal agency. The
sample is adequate for this exploratory research.
In newspapers, magazines, journal articles, company annual reports and press
releases, and in response to phone interview questioning, companies that have submitted
applications to build new nuclear facilities most often cited concerns about climate
change and emissions regulation as driving their renewed interest in nuclear power. The
volatile price of fossil fuels (particularly natural gas), the ability to secure federal loan
guarantees, the mandate for energy companies to be able to meet future demand for
electricity, and a firm’s past experience with operating nuclear reactors also influenced
that decision. (See Table 3 at the end of this Chapter.) Thus, a picture emerges showing
companies becoming increasingly aware that carbon taxes or a cap and trade system
designed to curb greenhouse gas emissions lie in the not too distant future. They realize
that either of those options will affect their ability to produce electricity using coal,

increasing their generating costs as they implement cleaner coal technologies or limiting
the amount of coal-fired electricity they can produce. Higher and more widely
fluctuating prices for natural gas and oil increase the risk associated with reliance on
either of those sources. But the companies need something to meet customer demand for
electricity. So, with the financial backing of the federal government, they look to expand
their fleet of nuclear power plants, the non-carbon emitting baseload generation they will
need in the years to come.
But the story is not quite that simple. As explained below, companies have
followed different paths to arrive at their decisions to submit an application for a
combined construction and operating license to the NRC, and each of them faces a
unique set of constraints and opportunities. Not all of the companies submitting
combined construction and operating license applications to the NRC are discussed. The
selection represents those for which contact information was available and whose
representatives responded to requests for telephone interviews during a five month period
in the spring of 2009. That selection presented does provide a look at the wide range of
factors driving the interest in new nuclear power plants.
4.1 NRG Energy
With its September 20, 2007 submission, NRG Energy became the first company
to file a complete “one-step” construction and operating license application with the
NRC. 172

172

“First Full COL Application Submitted,” Nuclear Engineering International, November 2007,
Vol. 52, No. 640, p. 4; “NRG Energy Asks NRC for COLA to Build 2,700 MW in Nuclear
Capacity,” Power Engineering, October 2007, Vol. 111, No. 10, p. 14; Vicki Vaughn,
“Application is First in Decades for New Nuclear Reactor,” San Antonio Express-News,
September 24, 2007.

NRG was founded in 1989 and has operated as a wholesale power generating
company, with facilities reaching from New York to California (but mostly concentrated
in the Northeast). 173 In 2003, the company filed for Chapter 11 bankruptcy, emerging a
year later. It acquired an ownership stake in the South Texas Project, a two-unit nuclear
plant outside of Houston, TX, in 2006. Then, in June 2006, NRG announced its
intentions to partner with General Electric in constructing two new Advanced Boiling
Water Reactor units at the South Texas Project (STP). (The G.E. ABWR design initially
had been certified by the NRC in 1997, but it would need some modifications to
accommodate an updated control room and the safety systems required in a post 9/11
world.)
NRG signed an agreement with Toshiba of Japan to construct the two ABWR
reactors. 174 According to David Crane, CEO of NRG, “Toshiba has an unblemished
record of on time, on budget delivery of advanced nuclear plants and we look forward to
working with them to make this essential no-carbon baseload plant a technical,
commercial and environmental success.” 175 Austin Energy, co-owner of the existing

173

“Resource News: Market Commentary on NRG Energy, Inc.,” M2 Presswire, June 11, 2007,
http://goliath.ecnext.com/coms2/gi_0199-6416405/Market-Commentary-on-NRG-Energy.html,
(accessed February 14, 2008); “Resource News: In-Depth Research on NRG Energy, Inc.,” M2
Presswire, March 1, 2007, http://goliath.ecnext.com/coms2/gi_0199-6294936/In-DepthResearch-on-NRG.html, (accessed February 14, 2008).
174

“Toshiba Signs EPC Agreement with STP Nuclear Operating Company,” March 2, 2009,
http://nuclear.energy-businessreview.com/news/toshiba_signs_epc_agreement_with_stp_nuclear_operating_company_020309/,
(accessed April 22, 2009).
175

“NRG Energy Signs Project Services Agreement with Toshiba Corporation for South Texas
Project Nuclear Power Plant Expansion,” Company News Release, August 9, 2007,
http://ir.nrgenergy.com/phoenix.zhtml?c=121544&p=irolnewsArticle_Print&ID=1038695&highlight=, (accessed February 14, 2008).

units, bowed out of the project due to concerns over the cost, schedule, and financial risk
associated with the project; the city of San Antonio (through CPS Energy) remained a
partner. 176 For CPS Energy, a diversified fuel mix was essential for keeping its
customers’ electric bills low and nuclear fit well into that mix:
Nuclear is the best choice for additional power because it is safe, costeffective and provides a clean source of energy. . . Nuclear fuel costs
remain significantly lower than coal, natural gas and renewables. Also, the
operating costs of nuclear plants have remained steady over time. Finally,
nuclear is an environmentally friendly source of energy because it does not
emit any greenhouse gases or other air pollutants into the atmosphere.177
The two companies signaled early in the project that they looked to nuclear power to
provide a source of baseload electricity with a relatively low, stable cost and essentially
no carbon dioxide emissions.
Thad Hill, President, NRG Texas, echoed those sentiments. In an article in the
Houston Chronicle in October of 2007, Hill was quoted as saying, “The market is ready
for new nukes, especially in Texas where consumers have seen electric rates rise because
of higher natural gas prices. What Texas needs is more fuel diversity.” Hill also
expressed his belief that the federal government would soon legislate carbon. “Nukes . . .
have no carbon emissions, so by the time the new STP units are operational, they’re
likely to have a built-in tax benefit.” 178

176

“NRC Postpones Public Comments on STP Units,” Bay City Tribune, February, 18, 2008;
Vicki Vaughn, “Nuclear Stakes Could Change,” San Antonio Express-News, February 12, 2008,
http://www.slate.com/id/2176189/, (accessed February 21, 2008).

177

“Frequently Asked Questions About Nuclear Energy,” http://www.citypublicservice.com,
(accessed February 22, 2008).
178

“The Nuclear Option Detailed (Updated),” October 19, 2007,
http://blogs.chron.com/lorensteffy/2007/10/the_nuclear_opt_1.html, (accessed February 21,
2008).

The desire to turn toward a non-carbon-emitting source also appeared in a
Fortune magazine article, “The Man Who Would Be Mr. Clean,” that described NRG as
“a ferocious polluter, responsible for generating more than 70 million tons of atmospheric
carbon annually,” and tying NRG for eighth place among U.S. carbon emitters. “NRG
overall is fundamentally about coal.” But, according to CEO Crane, “If we clean up our
carbon situation over the next 20 years, principally with nuclear, then we will be seen as
clean.” 179 Crane has become a zealous supporter of federal cap and trade regulation. He
does not believe wind and solar power, conservation, and efficiency can solve the U.S.
energy problems and thus backs futuristic coal and nuclear technology. However, “[h]e
needs scissors to cut through red tape so NRG can bury sequestered carbon. . .He needs
support for his burgeoning nuclear program: tax credits, loan guarantees, insurance to
cover licensing delays, and federal dollars to educate nuclear engineers. . .” 180 Thus,
although investing in nuclear and clean coal may be the right thing to do, Crane has
indicated that NRG cannot, and perhaps will not, do so without support from the federal
government.
In a startling turn of events, in February of 2008, NRG asked the NRC to delay
indefinitely its application, citing issues with vendor support and the completeness of the
ABWR reactor design. 181 However, in early 2009, the NRC reinstituted the application

179

“The Man Who Would be Mr. Clean,” Fortune, December 24, 2007, Vol. 156, No. 13, p. 69ff.

180

Ibid.

181

Dan Caterinicchia, “NRG Energy Nuclear Project Delayed,” February 14, 2008.
www.chron.com/disp/story.mpl/ap/fn/5541925.html, (accessed February 18, 2008); Tom Fowler,
“Snags Seen for Nuclear Power,” February 15, 2008,
www.chron.com/disp/story.mpl/headline/biz/5546664.html, (accessed February 18, 2008);
“Nuclear Application Delayed,” The New York Times, February 14, 2008.

review. Toshiba had signed an engineering, procurement, and construction agreement
with South Texas for the new reactors. In addition, NRG and Toshiba announced they
had formed a new firm, Nuclear Innovation North America, to bring the ABWR to the
United States. 182
Because Texas deregulated its electricity markets, NRG cannot pass on the costs
of new nuclear power plants directly to its customers through rate increases. To spread
the investment risk, NRG, like other utilities in deregulated states, hopes to partner with
other companies. Although CPS would provide some of the funds for the project, Crane
had told reporters “having a Japanese partner might help the company obtain the financial
support from the Japanese government, along with the U.S. loan guarantees and other
incentives for nuclear generation. . .” 183 The Toshiba deal undoubtedly will help Crane
and NRG get that extra support.
Having Toshiba as a partner also will help calm the fears of NRG investors and
lenders. According to CEO Crane, “the one principal risk you cannot lay off is who’s
going to build this thing on time and on budget.” 184 Since it has a financial stake in the
project, Toshiba has every incentive to meet those criteria. 185

182

Matthew L. Wald, “NRG Energy Sets Up an Entity to Build Nuclear Plants,” The New York
Times, March 26, 2008, Section C, p. 2.
183

“Update 1-- Utility Delays Nuclear Vote; NRG Seeks Partners,” October 2, 2007,
http://www.reuters.com/article/bondsNews/idUSN0244497720071002, (accessed March 19,
2009).
184

Wald, March 26, 2008.

185

“The Power Broker,” Smart Money, October 2008, pp. 22 – 23.

Still, Crane would like the public to believe in his commitment to the environment
above all . 186 Shortly after the application for the STP units was announced, he
proclaimed, “It is a new day for energy in America. Advanced technology nuclear power
plants like STP 3 & 4, generating a vast amount of electricity cleanly, safely and reliably,
will make an enormous contribution toward the greater energy security of the United
States. But equally, this announcement heralds a new day for the environment.” 187
Later, in the interview with SmartMoney magazine, he admitted, “Global warming is just
a massive issue. Like every CEO, I’m trained that it’s all about shareholder value and
almost everything is a bottom-line question. But when I looked at possible consequences
of global warming, it’s a moral obligation . . . the more important thing is to do
something about global warming; every year we delay makes the remedies more
severe.” 188
In short, environmental/global climate change issues seem to have dominated
NRG’s initial decision to build a new nuclear power plant, and the cost of fuel supplies
was a factor. However, construction will not occur without financial backing of its
partners and the U.S. government.
4.2 Entergy Operations, Inc.
The River Bend Nuclear Power Station lies not too far from NRG’s South Texas
Project, near St. Francisville, LA. Entergy Operations has chosen River Bend as the site

186

“NRG Facing Carbon Head On; Betting on Nukes,” Natural Gas Week, June 8, 2007, p. 1.

187

“The Power Broker,” Smart Money, October 2008, p. 22 – 23.

for one of the new reactors planned for its nuclear fleet. Entergy initially chose the G.E.Hitachi Economic Simplified Boiling Water Reactor for the site. Design concerns and
issues with component costs (“They essentially tripled the price they wanted to build it
for”) led Entergy to ask the NRC to suspend its review of their COL in January of
2009. 189 G.E.-Hitachi has submitted revised design documents to the NRC; Entergy
continues to examine designs from other vendors. 190
Like many of the electric companies in the U.S., Entergy has its roots in regional
utilities that were combined under a large holding company. 191 In the case of Entergy,
Middle South Utilities united the operations of smaller utilities in Arkansas, Mississippi,
and Louisiana. In 1974, Middle South Utilities formed Middle South Energy to bring its
first nuclear plant on line at Grand Gulf, MS. Cost and schedule overruns plagued the
project and the second unit at the site was cancelled. In a bid to distance itself from
controversy surrounding paying for Grand Gulf through rate increases, Middle South
changed its name to Entergy in 1989. 192 It wasn’t until 1999 that Entergy began
investing in more nuclear capacity, buying the Pilgrim plant in Massachusetts, and
189

Danny Barrett, Jr., “Grand Gulf Sets Sights on Ramping Up Output,” The Vicksburg Post,
October 8, 2009,
http://www.vicksburgpost.com/articles/2009/10/08/news/doc4ace0c6e5708d778634565.prt,
(accessed October 25, 2009); Eileen O’Grady, “Update 2 – Two US Firms’ Reactor Deals with
GE Hitachi Fail,” January 9, 2009,
http://www.reuters.com/article/rbssUtilitiesMultiline/idUSN0931235920090110, (accessed
March 19, 2009).
190

Barrett.

191

“Entergy History,” http://0-premiumhoovers.com.cals.evergreen.edu/suscribe/co/history.xhtml?ID=ffffrfhtcxfskcsffh, (accessed July
8, 2008).
192

Ibid; Dianna Solis, “Electric Company Wants to Change its Name and Image—Middle South
Utilities Inc. Chooses Entergy, Joining Others in ‘En’ Craze,” The Wall Street Journal, January
31, 1989, p. 1.

contracting to operate Nine Mile Point in New York. 193 Entergy subsequently purchased
the Fitzpatrick and Indian Point 3 units, also in New York, Vermont Yankee (in
Vermont), and the Palisades Nuclear plant in Michigan. 194
In 2007, Entergy announced plans to spin off half of its nuclear power plants and
create a stand alone, publicly traded nuclear energy company. 195 Why? According to an
article in the Wall Street Journal dated November 6, 2007,
Less than a decade ago, Entergy was picking up distressed nuclear assets
on the cheap. In one case, it bought a plant for little more than the value
of the fuel on hand . . . The company reaped most of its third-quarter [2007]
profits from its nuclear fleet, not its regulated utilities . . . Entergy, Exelon,
and other consolidators have increased the productivity of nuclear plants, and
they are able to collect rising prices in deregulated markets as supply margins
shrink . . . During the next five years, sales contracts on the output of the five
plants Entergy plans to spin off are expiring. It is negotiating new prices that
are as much as triple the old ones. 196
It would seem that for Entergy, nuclear plants are the “cash cows” of its business.
Decoupling those five nuclear power plants also protects Entergy from any costs
that would be associated with updating, modifying, or eventually decommissioning and
dismantling the facilities. 197 The operating license for Pilgrim 1 expires in 2012. The
NRC currently is reviewing a license renewal for Indian Point 3 (the current license
expires in 2015). Nine Mile Point, the oldest of the plants, started operations in 1969 but
193

Matthew L. Wald, “Nuclear Power’s Second Act; Rising Demand for Electricity Revives
Aging Reactors,” The New York Times, December 20, 2000.

194

Rebecca Smith, “Entergy to Buy Nuclear Plants from Power Utility,” The Wall Street Journal,
February 15, 2000, p. B15.
195

Rebecca Smith, “Entergy Nuclear Spinoff Taps Rising Plant Values,” The Wall Street Journal,
November 6, 2007, p. A.15.
196

Ibid.

197

Ken Silverstein, “Spinning Value,” Energy Biz Insider, December 1, 2008.

has had its license extended until 2029. 198 No one knows what expenses will be incurred
by those older plants.
Danny Blanton, Entergy Nuclear media contact, indicated in a February 14, 2009
interview that Entergy’s interest in adding new nuclear plants has been driven by three
main factors: (1) Concerns about carbon/greenhouse gas emissions, (2) The current
“energy crisis”, and (3) Nuclear power’s ability to provide large baseload capacity with a
small “footprint.” 199 He did not mention the profit potential. Instead he pointed out that,
like David Crane of NRG Energy, Entergy management supports cap and trade programs
for carbon emissions. Under such programs, Entergy would receive or would buy a set
number of carbon emissions allowances, which would allow it to continue to operate its
fossil-fueled facilities. Unused allowances could be sold or traded to other companies
who emit more carbon. According to Blanton, since nuclear plants do not give off carbon
dioxide, adding more of them to the generating fleet would mean Entergy would not use
and might profit from selling its emissions allowances.
In addition, “[t]he population is growing and we all have more ‘stuff’” (Blanton
Interview). 200 Entergy plans to address that increasing demand using clean air energy
sources, like nuclear. Entergy also prefers nuclear because it would take only one pellet
of uranium to produce the same amount of electricity as one ton of coal—giving nuclear
a much smaller environmental footprint than its rival in baseload generation, coal.

198

“Nine Mile Point Nuclear Station, New York,”
http://www.eia.doe.gov/cneaf/nuclear/page/at_a_glance/reactors/nine_mile.html, (accessed
October 25, 2009).

199

Danny Blanton, Nuclear Media Contact, Entergy, Telephone Interview of February 18, 2009.

200

Ibid.

When asked specifically about the regulatory and licensing process changes that
had occurred since the first round of reactor development, Blanton acknowledged that
federal loan guarantees were a big part of Entergy’s decision about investing in new
nuclear generation, mainly due to the high capital costs associated with building the
plants. Unfortunately, the program expires in September of 2009—long before any
company will have its required NRC license approval in hand. Blanton went on to say
that the extension of the Price-Anderson Act was not as critical to Entergy as the loan
guarantees.
Other factors taken into account in Entergy’s decision to apply for a construction
and operating license included the NRC’s streamlining of the licensing process, the
ultimate cost to the customers, and other fuel options available. “We want to produce
electricity that’s affordable for the people. And the most affordable is nuclear. But
Entergy is not closing the doors on other renewable sources. What you can use depends
on your baseload needs and your geographic region. There are parts of Mississippi that
can’t get a radio signal let alone enough wind to produce electricity! 201
Recall that in their joint letter to Mr. Howard Borgstrom of the DOE, executives
from Entergy, Constellation Energy Group, NRG Energy, and Exelon stressed their belief
that loan guarantees were “critical to their continued efforts to develop the first new
nuclear generating units to be ordered and built in the United States in nearly thirty
years” 202 and that “the size and scale of nuclear projects, and the multi-year commitments

201

Ibid.

202

that need to be made by private industry, make it imperative that DOE create certainty in
the near-term around the future availability of the Title XVII Loan Guarantee Program
for nuclear power projects.” 203 Thus, while Entergy’s Senior Vice President of Finance
focused (understandably) on the monetary aspects of the decision to build a new nuclear
power plant, Mr. Blanton’s comments seem to indicate that the loan guarantees are only
part of a wider array of forces behind Entergy’s interest. The interest in new nuclear
power stems from Entergy’s need to invest in non-carbon emitting baseload generation,
but it is the federal incentives behind the nuclear program that make it highly desirable
and fiscally feasible at this particular point in time.
4.3 Duke Energy
The environment and the potential for nation-wide restrictions on carbon
emissions also played a role in Duke Energy’s decision to apply to build a new nuclear
power plant. Founded in 1899 as Catawba Power but renamed Duke Power in 1924,
Duke has been a mainstay in Southeast for over a century.204 The company now serves
over four million customers in Ohio, Kentucky, Indiana, and the Carolinas. Most of
Duke’s generation facilities run on coal or natural gas, but it does operate seven reactors
at three sites in North and South Carolina.
Duke’s CEO, Jim Rogers, immersed himself in the science of global warming as
early as the 1990s and became enthusiastic about the technological opportunities it
presented. “Rogers’s environmentalism is practical, enthusiastic and intrigued by cleanhttp://www.lgprogram.energy.gov/nopr-comments/comment41.pdf, (accessed March 19, 2009) p.
1.
203

Turnage et al., p. 3.

204

“Duke Energy, History,” www.duke-energy.com (accessed January 19, 2009).

tech innovations, not given to heartstring-tugging rhetoric about vanishing species or
redwood trees.” 205 Rogers became an outspoken advocate of a market based approach to
limiting greenhouse gas emissions, testifying before Congress in favor of a cap and trade
program for carbon dioxide. 206 In 2007 he made it known that the issues related to
carbon emissions served as the “tipping point” for the company’s decision about nuclear
power: “You wouldn’t take such a big risk if you weren’t going to be in a carbonconstrained world.” 207
Even as Rogers publicly proclaimed Duke’s ‘green’ intentions, other company
spokespeople conveyed different messages. For example, early in 2005, Bryan Dolan,
Duke’s Manager of Nuclear Projects, told the New York Times that Duke became
increasingly interested in nuclear power based on the costs of alternatives. “[T]he
numbers we have today tell us that nuclear will be very competitive.” The price of
natural gas had nearly tripled and showed no signs of falling, and analysts were unsure of
the potential costs of coal-fired generation due to uncertainty surrounding its
regulation. 208 The 2005 Summary Annual Report blended that sentiment with the
environmental issues.

205

Clive Thompson, “A Green Coal Baron?” The New York Times, June 22, 2008.

206

“Duke Energy CEO Jim Rogers Voices Support for USCAP’s Blueprint for Legislative
Action,” PRNewswire, January 15, 2009, http://sev.prnewsire.com/oilenergy/20090115/CLTH04315012009-1.html, (accessed January 21, 2009); Bruce Henderson,
“Duke Joins Plan to Lower Emissions,” McClatchy – Tribune News, January 16, 2009,
http://www/proquest.umi.com/pqdweb?did=1627783831&Fmt=3&clientId=10024&RQT=309&
VName=PQD, (accessed March 12, 2009); Reshma Kapadia, “Duking it Out Over Pollution,”
Smart Money, April 2009, pp. 16 – 18.
207

“Boom,” The Economist, Vol. 383, No. 8531, June 2, 2007, pp. 20 – 22.

208

Matthew L. Wald, “Duke Power May Seek to Build Nuclear Plant,” The New York Times,
March 15, 2005.

[G]rowing concern about greenhouse gases, skyrocketing fuel prices
and a need to develop a next generation of capacity will challenge the
industry like it has never been challenged before . . . Our newly
combined fleet [Duke plus Cinergy] uses a diverse combination of fuels
—nuclear, coal, gas and hydro—reducing our dependence on any one
commodity. 209
The 2006 Summary Annual Report added yet another dimension to the problem:
Customer demand. Duke reported gaining 40,000 to 60,000 customers each year in the
Carolinas. “We are required by law to meet the electric power needs of our customers as
economically and reliably as possible.” 210 The Report then summarized actions taken by
Duke in the previous year to meet the growing demand, including building new power
plants; using a diverse mix of fuels and technologies to limit future price, reliability, and
environmental risks; obtaining legislation and regulatory treatment that would allow
Duke to recover financing costs as they constructed new and more efficient power plants;
and helping shape federal rules limiting carbon to ensure Duke customers were fairly
treated. Environmental issues received a bit more attention later in the report, but the
approach was tempered by financial obligations. “[W]e are mindful of our environmental
responsibilities . . . We are committed to making the best technological choices, ones that
will limit our emissions and optimize our investments so that we can keep our prices
competitive.” 211 However, the crucial piece in constructing new nuclear power plants is
the company’s ability to recover up front its financing costs during construction. “We
209

“What Can We Expect from the Merger of Duke Energy and Cinergy? Duke Energy 2005
Summary Annual Report,” http://www.dukeenergy.com/pdfs/Duke_Energy_2005_Annual_Report.pdf, (accessed March 13, 2009). p. 4.
210

“Changing Minds. Changing Habits. Duke Energy 2006 Summary Annual Report,”
http://www.duke-energy.com/pdfs/Duke_Energy_2006_Annual_Report.pdf, (accessed March 13,
2009). p. 7.
211

Ibid, p. 10.

have been clear that we will not move forward with a nuclear plant unless we know that
we can recover our financing costs in rates as we build.” 212
Duke titled its 2007 Annual Report “Building Bridges to a Low-Carbon Future.”
With favorable cost recovery legislation on the books, the company emphasized the role
nuclear power would now play in that low-carbon future. They had filed a construction
and operating license application with the NRC to build a two-unit facility in Cherokee
County, SC. “We are using our more than three decades of experience in building and
operating nuclear plants to plan a new 2234 megawatt power plant in South Carolina—a
plant that will have zero CO2 emissions.” 213 Despite the fact that the first unit was not
anticipated to be on line until 2018, Duke reassured its investors. “People today aren’t
used to looking far into the future or contemplating issues of the scale and complexity of
global climate change. We focus on the quick fix. We deal with problems now—then
we move on to the next one. Climate change is different. The future can only be
changed if we begin today and keep going . . .” 214
For Rita Sipe, who grew up in the Southeast and had many family members
working in the energy industry, taking a job with Duke Energy seemed a natural thing to
do. 215 She now serves as Nuclear Media Relations contact. According to Sipe, the Duke
license application for a new nuclear power plant was driven, first and foremost, by the

212

Ibid, p. 8.

213

“Building Bridges to a Low-Carbon Future, Duke Energy 2007 Summary Annual Report,”
http://www.duke-energy.com/pdfs/Duke_Energy_2007_Annual_Report.pdf, (accessed March 13,
2009). p. 19.
214

Ibid, p. 25.

215

Rita Sipe, Nuclear Media Relations, Duke Energy, Telephone Interview of February 20, 2009.

needs of the customer. The local Utilities Commissions require Duke to file a yearly
resource plan, looking at existing generating capacity, current and projected demand, and
plans for meeting the demand. Due to the long lead time for designing, permitting, and
building new baseload generation facilities, planning needs to start 10 to 15 years in
advance. Duke has not added new baseload capacity since the Catawba nuclear plant
came on line in 1986. Some of the coal plants now in use date back to the 1920s and it is
not clear how long they can continue to serve. Duke will need new capacity.
Ellen Ruff, Duke’s first President of Nuclear Generation, echoed Sipe’s focus on
the customer: “[W]e’re going to have reliable, affordable source of generation for our
customers, because at the end of the day, this is about our customers . . . primary in our
obligation is to have reliable, low-cost electricity available . . . We will always have to
get there.” 216
Both Sipe and Ruff deem the choice of nuclear power as driven in part by the
possibility of carbon legislation in the United States. From Sipe: “Nuclear doesn’t emit
CO2” (Interview). And according to Ruff, “[W]e are very anxious to find a way to
develop nuclear in terms of being a clean source of energy, and non-carbon emitting.” 217
In addition, Sipe views nuclear as the safe option, based on the amount of training
operators receive (at Duke every fifth week is spent in training) and on the company’s
history. “Duke has years of experience. And, nuclear is quite a regulated industry. It’s
very structured with lots of procedures and processes. It’s also an industry that prides
216

Adam Bell, “Forging Next Nuclear Age: Ellen Ruff is in Charge of Duke Energy’s First New
Nuclear Plant in 20 Years,” McClatchy – Tribune News, January 4, 2009,
http://www.proquest.umi.com/pqdweb?did=162118251&Fmt=3&clientId=10024&RQT=309&V
Name=PQD, (accessed March 12, 2009).
217

Bell.

itself on freely sharing information. If one plant experiences something, they share that
with the others.”
As for the role of federal loan guarantees in the Duke decision to look into new
nuclear plants, Sipe contends that even without loan guarantees, the company would be
interested in new nuclear.
The picture that emerges for Duke Energy is one dominated by a need to respond
to customers’ growing need for electricity and a desire to maintain a diversified fuel base
to adapt to changing prices (and availability), underscored by a real concern about global
climate change and its potential impact on electrical generation in the U.S. On the
financial side, loan guarantees are nice, but the ability to recover costs during
construction (“Construction Work In Progress” or CWIP financing) is a necessity.
4.4 Progress Energy Florida
Baseload power fuel diversification has driven Progress Energy Florida’s interest
in new nuclear plants. According to Rick Kimble, Manager of Nuclear Communications,
in a January 2009 interview, Florida law mandated that power companies always build
the least cost option for baseload power. Until recently, that meant gas-fired plants.
When the 2005 hurricanes in the Gulf of Mexico disrupted gas processing in Texas and
Louisiana, gas prices soared. Since Florida law also allows those fuel prices to be passed
on to the customer, local residents saw their electricity bills rise as well, creating hardship
particularly for those on fixed incomes (such as retirees). With forecasts showing extra
capacity would be needed by about 2017 or 2018, Progress Energy began looking into
alternative sources for baseload power.

Whereas in some parts of the country utilities may be able to purchase power via
long term contracts from neighboring states, few transmission lines join Florida to its
neighbors. The Wall Street Journal described Florida as “a virtual island to which it is
difficult to export power.” 218 In addition, utilities that might serve parts of Florida also
expect to see increases in demand for electricity and are reluctant to enter into long-term
contracts.
Since Florida has no hydropower for Progress Energy to tap, and with an
expectation that coal may be subject to a carbon tax in the near future, the company
turned to nuclear power to supplement its baseload generating capacity. The 2006
Annual Report stated, “We face fuel price volatility and complex environmental issues
such as global climate change. On the positive side, there’s an opportunity to reap the
benefits of today’s greater potential for energy efficiency and renewable energy as well
as for new advanced nuclear and clean-coal technologies.” 219 The 2007 Annual Report
indicated that “[t]oday we face several new energy realities: growing population and
energy demand, the need to reduce greenhouse gas emissions and address global climate
change, and concerns over dependence on fossil fuel. At Progress Energy, we believe
strongly that new nuclear is a good option for addressing these issues.” 220 Likewise, Jeff
Lyash, President, Progress Energy Florida, stated, “We believe that new nuclear

218

Nikhil Deogun and Rebecca Smith, “FPL Group, Energy Strike Merger Deal—Combination
Could Create Top Electric Producer, Serve 6.3 Million People,” The Wall Street Journal, July 31,
2000, p. A.3.

219

“The Road Ahead: Shifting into High Gear,” Progress Energy 2006 Annual Report, Raleigh,
NC: Progress Energy, Inc., March 2007, p. 4.

220

“We’re Looking at Power in a New Light,” Progress Energy 2007 Annual Report, Raleigh,
NC: Progress Energy, Inc., March 2008, p. 11.

generation is a critical hedge against future risk of volatile and increasing fossil-fuel
prices, and the likely significant future costs of emissions regulations.” 221 Bill Johnson,
Chairman, President and CEO of Progress Energy, Inc., reiterated the company’s position
in 2008: “The over-arching issue is how to address climate change and demand growth
while maintaining a secure supply, reliable service and affordable rates for customers and
creating shareholder value for investors. . .” 222 Even the data sheets about the Levy
County, FL nuclear project claim that “[w]ith growing concerns about climate change,
nuclear power is a sound environmental choice. Nuclear also protects customers from
price volatility associated with oil and natural gas prices and ensures a reliable supply of
electricity.” 223 For Progress Energy then, the volatility of natural gas prices, potential
taxes on carbon emissions, a desire to address global climate change, and increasing
demand for electricity have been and continue to be the key drivers of capacity expansion
plans.
In order for Progress Energy Florida to expand its nuclear fleet (it currently
operates one nuclear reactor at Crystal River, FL), it had to be able to recover some of the
costs of the new plant during construction. 224 According to spokesman C.J. Drake,
“Early cost-recovery is a key for Progress. If it weren’t for that, nuclear would be too
221

“Update 1--Progress Seeks Florida OK to Build New Reactors,” March 11, 2008,
http://www.reuters.com/article/companyNews/idUSN1160205320080311, (accessed March 19,
2009).

222

“Progress Energy CEO Says Company Focused on Securing the Energy Future,” Company
Media Release, February 29, 2008, http://www.progress-energy.com/aboutus/news/article.asp,
(accessed January 22, 2009).

223

“Frequently Asked Questions,” www.progressenergy.com/aboutenergy/poweringthefuture_florida/levy/faq.asp, (accessed January 22, 2009).
224

Rick Kimble, Manager of Nuclear Communications, Progress Energy Florida, Telephone
Interview of January 29, 2009; “Update 1-- Progress Seeks Florida OK to Build New Reactors.”

expensive.” The Florida legislature has agreed. Section 366.93 of the Florida statutes
allows for up front recovery of nuclear power plant costs, including nuclear related
transmission expenses; and the annual expensing of pre-construction costs (such as costs
related to site selection) and the carrying costs on the construction cost balance. 225 The
early cost recovery program is expected to save customers about $13 billion in interest
and other charges over the life of the plant. Progress Energy Florida customers began
paying for the new Levy County nuclear facility in January of 2009.
Unlike other utilities, Progress Energy Florida will not rely on federal loan
guarantees to assist in gaining financing for the plant. Rick Kimble mentioned that
Progress was not willing to accept some of the terms of the loan guarantee program
(DOE taking first mortgage rights on the facility for example). In addition, the program
has high costs: $50 million for the first part of the application and about $450 million for
the remaining parts. 226 Progress Energy remains optimistic that it could secure loans on
its own, without the government guarantees.
Danny Blanton of Entergy had described the loan guarantees as critical to that
company’s reactor construction program, whereas the continuation of the Price-Anderson
insurance was nice but not absolutely necessary. Progress Energy chose not to rely on
loan guarantees, but, according to Kimble, the Price-Anderson Indemnity Act had to

225

Bill McNulty, “Nuclear Power Plant Cost Recovery in Florida,” PowerPoint Presentation to
the Louisiana State 2008 Energy Summit,
http://www.enrg.lsu.edu/Conferences/energysummit2008/es2008_mcnulty.pdf.
226

Rick Kimble, Manager of Nuclear Communications, Progress Energy Florida, Telephone
Interview of January 29, 2009.

remain intact for Progress to pursue new nuclear plant construction.227 Limitations on
liability resulting from nuclear accidents are important to Progress Energy.
Progress Energy also has expressed anxiety about the fluctuations in price of
alternative fossil fuel supplies and about meeting customers’ growing energy demand,
and is therefore looking into new nuclear power. Progress Energy is concerned about the
possible taxes on greenhouse gas emissions and wants to minimize the cost impacts on
customers and shareholders. Interestingly, unlike utility companies to the west and to the
north of them, neither Duke nor Progress Energy has relied on the availability of loan
guarantees in their decision to submit an application to build a new nuclear power plant.
However, both revealed the importance of CWIP financing for that new construction.
(Note: As of this writing, Progress Energy Florida is the only company to submit
a COL during 2009. On June 30, 2009, the NRC received the application to construct
and license two AP1000 units at the Turkey Point site near Homestead, FL. 228 )
4.5 Tennessee Valley Authority (TVA)
As part of his plan to lift the country from the depths of the Great Depression,
President Franklin D. Roosevelt asked Congress to create a natural resource agency
“clothed with the power of government but [which] possessed of the flexibility and
initiative of a private enterprise.” 229 Thus, the Tennessee Valley Authority, or TVA, was
born. It has grown from an organization that taught farmers how to get the best yield
from their crops into one of the country’s largest electric companies. The TVA currently
227

Ibid.
“Turkey Point, Units 6 and 7 Application,” http://www.nrc.gov/reactors/newreactors/col/turkey-point.html, (accessed 9/15/09).
228

229

“From the New Deal to a New Century: A Short History of TVA,”
http://www.tva.gov/abouttva/history.htm, (accessed May 3, 2009).

operates 11 fossil fuel-fired plants, 29 hydroelectric dams, three nuclear facilities (six
reactors) and six combustion turbine facilities, and is seeking to add more generation
capability. 230
The TVA started construction of the first of its 17 planned nuclear reactors in
1967. Browns Ferry Unit 1 began operations in 1974; Unit 2 followed in March of
1975. 231 Unfortunately, that same month, a maintenance worker using a candle to check
for air leaks around electrical cables ignited polyurethane foam insulation. The fire
spread quickly through the wall, damaging emergency core cooling system equipment,
and backup generators for Units 1 and 2. 232 TVA repaired the damaged units and
completed a third unit on the site—Unit 3 commenced operations in 1977.
Undeterred, TVA completed two additional units at the Sequoyah Nuclear Plant
and brought them on line in 1980 and 1981. But the aftermath of the Three Mile Island
accident in 1979--the changes in NRC regulations and resulting cost increases for nuclear
plants--led TVA to cancel orders for eight reactors whose construction it had already
postponed and place four others on hold. 233 Then, due to concerns over faulty
workmanship, inadequate training of personnel, violations of safety and security
230

“Overview,”
http://premium.hoovers.com.cals.evergreen.edu/subscribe/co/overview.shtml?ID=ffffcfcjfffrxxyf
yt, (accessed July 8, 2008).
231

“Browns Ferry Nuclear Power Plant, Alabama,”
http://www.eia.doe.gov/cneaf/nuclear/page/at_a_glance/reactors/brownsferry.html, (accessed
October 27, 2009).

232

David Dinsmore Comey, “The Fire at the Brown’s Ferry Nuclear Power Station,” in Not Man
Apart, CA: Friends of the Earth, 1976, http://www.ccnr.org/browns_ferry.html#ca, (accessed
October 27, 2009).

233

Judith Miller, “For Nuclear Power, New Blows,” The New York Times, May 29, 1982, p. 2.35;
“Around the Nation; T.V.A. Cites Lack of Need in Scrapping 4 Reactors,” The New York Times,
August 26, 1982, p. A.16.

regulations, a culture of indifference, and persistent management problems, the NRC shut
down all TVA’s operating reactors in 1985. 234
TVA was determined not to turn its back on its nuclear investment. The
Authority hired a group of people experienced in the Navy nuclear propulsion program
and in the private nuclear industry to oversee its reactor projects. 235 Admiral Stephen A.
White took over as director. 236 The technical knowledge, high standards for excellence,
and leadership skills he brought with him helped TVA gain the NRC’s approval for
restarting Sequoyah Unit 2 in 1988. 237 In 1991, after $1.3 billion in improvements, TVA
was granted permission to reopen Browns Ferry. 238
In the mid-90s, the TVA announced that it would not complete three partially
built reactors that had been ordered in the 1970s: Watts Bar 2 in Tennessee and
Bellefonte 1 and 2 in Alabama. A slowdown in demand for electricity, increasing costs
and the time needed to build and license nuclear plants, and the failure of existing units to
operate as reliably and efficiently as expected all contributed to the decision. According
234

Matthew L. Wald, “T.V.A. Shuts Down Last Nuclear Plant,” The New York Times, August
24, 1985, p. 1.6; Stuart Diamond, “Management Cited as Key to Safety at U.S. Nuclear
Reactors,” The New York Times, May 23, 1986, p. A.10; Ben A. Franklin, “Nuclear Program of
T.V.A. Sharply Criticized,” The New York Times, March 2, 1986, p. A.29; Ben A. Franklin,
“T.V.A. Reactor to be Restarted,” The New York Times, March 23, 1988, p. A.18.
235

Ben A. Franklin, “The T.V.A. Mothballs its Nuclear Ambitions,” The New York Times, June 8,
1986, p. A.6.
236

“T.V.A. Reinstating Admiral as Manager of Nuclear Program,” The New York Times, January
8, 1987, p. B.9.

237

Ben A. Franklin, “T.V.A. Reactor to be Restarted,” The New York Times, March 23, 1988, p.
A.18; Matthew L. Wald, “Trouble at a Reactor? Call in an Admiral,” The New York Times,
February 17, 1989, p. D.1.

238

“After 6-Year Shutdown, Reactor Begins Warmup,” The New York Times, May 25, 1991, p.
1.9; Keith Schneider, “Ideas & Trends; Is Nuclear Winter Giving Way to Nuclear Spring?” The
New York Times, May 12, 1991, p. A.4.

to Craven Crowell, then TVA Chairman: “It’s the end of the line for this generation of
nuclear plants.” 239 Only 6 of its 17 reactors originally planned by TVA had been brought
on line.
Mr. Crowell’s prediction proved false when, in 2002, the Board of Directors of
the TVA voted to restart Browns Ferry Unit 1. The “reactor was left idle because its
capacity was not needed, but . . . with electricity demand growing, they needed a
generator that would not add to the region’s air quality problems.” 240 The TVA had been
implicated as one of the biggest emitters of nitrogen oxides, mercury, and carbon dioxide
in the power industry. 241 It needed to clean up its electrical generating fleet. This time,
Crowell told the Reuters news agency “I don’t see any other viable option for baseload
generation.” 242
The decision to restart Browns Ferry Unit 1 saved the TVA time and money. Unit
1 already had an operating license for the facility and could add capacity under that
existing license (increasing output from 1000 MW to 1300 MW). The project required
only five years to complete as opposed to 12 to 15 years for permitting and building a
new plant. The TVA did have to install about 150 miles of new cable and six miles of
new pipe, and had to maintain the proper documentation to ensure that all of the work

239

Matthew L. Wald, “T.V.A. Plans to Stop Work on 3 Partly Built Reactors,” The New York
Times, December 13, 1994, p. B.10.
240

David Firestone, “Utility Board Votes to Restart a Nuclear Reactor in Alabama That Has Been
Idle Since 1985,” The New York Times, May 17, 2002, p. A.12.

241

Neela Banerjee, “Study Ranking Utility Polluters Aims to Sway Emissions Debate,” The New
York Times, March 21, 2002, p. C.1.

242

“U.S. Power Industry Sees Nuclear Renaissance Near,” February 16, 2007,
www.reuters.com/article/bondsNews, (accessed March 19, 2009).

100

was up to contemporary nuclear construction standards. 243 But the price tag for the
project was only about $1.9 billion versus the $5 to 8 billion needed to design and build a
new nuclear power unit. The NRC also granted a 20-year license extension for the
facility. Browns Ferry Unit 1 reopened in May of 2007.
Bolstered by the Browns Ferry success, described by one analyst as a “rehearsal
for new plant construction,” 244 and with growing concern about the environment, the
TVA Board of Directors approved $2.5 billion over five years to update and complete
Watts Bar 2. (Watts Bar 2 was about 60% complete when the project was stopped.) The
Board also voted in favor of submitting an application to the NRC for a license to build
and operate two new reactors at its Bellefonte site in Alabama. 245
The TVA’s interest in new nuclear preceded the 2007 Board votes. According to
Terry Johnson of TVA Nuclear Communications, the TVA recognized the future need for
baseload generation in the early 2000s. 246 “TVA historically has experienced a 2%
demand growth each year. That means that every four to five years they need another
five to six hundred MW.” In 2004, they joined the NuStart consortium to help
demonstrate the new NRC reactor licensing process. 247 NuStart chose the AP1000 and
ESBWR reactor designs and the existing TVA Bellefonte site for the reference
243

Matthew L. Wald, “A Nuclear Reactor Reborn,” The New York Times, May 11, 2007, p. C.3.

244

Ibid.

245

“TVA Board Advances New Alabama Nuclear Reactors,” September 27, 2007,
http://reuters.com/article/companyNewsAndPR/idUSN2733770920070927, (access March 19,
2009).
246

Terry Johnson, Nuclear Communications, Tennessee Valley Authority, Telephone Interview
of March 10, 2009.
247

Ibid; John J. Fialka, “New Nuclear Plants in U.S. Get Study,” The Asian Wall Street Journal,
April 26, 2004, p. A.4.

101

applications it prepared in 2004 and 2005. Not only was the TVA familiar with
Westinghouse reactors, but it also had some of the infrastructure already in place from its
earlier work on the partly completed Bellefonte Units 1 and 2.
Johnson also mentioned that constructing new nuclear plants will allow the TVA
to shut down some of its older coal-fired facilities. The price of coal tends to be more
volatile than that of uranium. In addition, that move would reduce the uncertainty
associated with Congressional action on restrictions or taxes on the carbon emissions
from coal plants.
For the TVA, renewable sources of energy cannot provide the needed baseload
power. “Renewables require Mother Nature’s input. But she cooperates better in some
places than in others. Renewables also require distribution and storage facilities that may
not now exist.” 248 Conservation and efficiency efforts alone cannot meet the increasing
demand either, because “[e]ach person would need to conserve enough to offset the new
demand.” 249 Still, TVA has been upgrading the generators in their hydroelectric facilities
to increase electricity production without building new dams. And it will be looking to a
combination of hydroelectric power, nuclear, wind, solar, and methane gas from a
wastewater treatment plant near Memphis, Tennessee to provide about half of its
electricity generation by 2030.
Thus, with their coal facilities facing an uncertain future and having ruled out
renewable sources for baseload generation, TVA looks to new nuclear plants to help it
meet the growing demand for electricity. Completion of several of its original plants has

248

Johnson Interview.

249

Ibid.

102

helped TVA put their past experiences with nuclear construction behind them and has
given the company the confidence to move forward in completing two existing reactors
and in applying to construct one or two new AP1000s, at its Bellefonte site. 250
What role did loan guarantees play in TVA’s decision? TVA did not even apply.
First of all, being a federal agency, the TVA probably would not qualify for the
guarantees. Secondly, Bellefont Unit 1 was almost 90 % complete when construction
stopped, and Unit 2 was over 50 % finished. It is doubtful whether loan guarantees
devoted to advancing “new” and “significantly improved” technologies could be used to
complete those units. 251 However, any new AP1000 units might have met the DOE
criteria.
4.6 Constellation Energy Group
Although Constellation Energy Group traces its roots to gas lighting companies in
the Baltimore, Maryland area, it currently gets 35 % of its generation from coal, gas, and
oil; 61 % from nuclear power; and the balance from renewable sources. 252 Constellation,
then called Baltimore Gas and Electric, built its first two nuclear plants in the 1970s at
Calvert Cliffs in Maryland. In 2001, the company expanded its nuclear capacity with the
purchase of Nine Mile Point 1 and 82 % of Nine Mile Point 2 from Niagara Mohawk in
250

“NRC Restores Permit to Build Bellefonte Plant,” Chattanooga Times Free Press, March 13,
2009, http://www.timesfreepress.com/news/2009/mar/13/nrc-restores-permit-build-bellefonteplant/, (accessed October 27, 2009); “TVA Reconsiders Bellefonte Plans,” World Nuclear News,
August 10, 2009, http://www.world-nuclear-news.org/print.aspx?id=25784, (accessed October
27. 2009).
251

“Title XVII – Incentives for Innovative Technologies,” Public Law 109 – 58, August 8, 2005,
http://www.lgprogram.energy.gov/EPA2005TitleXVII.pdf, (accessed October 27, 2009).

252

“Constellation Energy Power Generation,”
http://www.constellation.com/portal/site/constellation/menuitem.16c4d66a696c12875fb60610025
166a0/, (accessed March 13, 2009).

103

up-state New York. Ginna Nuclear Operating Station, also in New York, was added in
2003. According to a November 26, 2003 article in The New York Times, the expectation
of high power prices in the deregulated New York market spurred those acquisitions. 253
The company’s pride in its nuclear operations shone through in its 2005 Annual
Report. “As one of the nation’s premier nuclear power plant owners and operators, we’re
demonstrating that nuclear power is reliable, cost-effective and environmentally
friendly.” 254 President Bush had chosen Calvert Cliffs to announce his energy policy that
year, advocating the expansion of “the one energy source that is completely domestic,
plentiful in quantity, environmentally friendly, and able to generate massive amounts of
electricity, and that’s nuclear power . . . It is time for this country to start building nuclear
power plants again.” 255
In 2005, Constellation had formed a partnership with Areva of France to develop,
manufacture, construct, and operate the largest nuclear reactor in the United States—
1600 MW(e)—and a fleet of standardized reactors nation-wide. 256 The venture, UniStar
Nuclear, also included the French utility Electricité de France (EdF) as a partner.
Constellation felt they had gained good experience from their nuclear operations and

253

Matthew L.Wald, “Rochester Utility Sells Nuclear Power Station,” The New York Times,
November 26, 2003.

254

“We Turn it On, Constellation Energy 2005 Annual Report,” Baltimore, MD:
Constellation Energy, April 2006, p. 15.
255

“President Bush’s Speech at Calvert Cliffs Nuclear Power Plant,” June 22, 2005,
http://somd.com/news/headlines/2005/2224.shtml.
256

“We Turn it On, Constellation Energy 2005 Annual Report;” Matthew L. Wald,
“Nuclear Power Venture Orders Crucial Parts for Reactor,” The New York Times, August
4, 2006, Section C, p. 2; Matthew L. Wald, “Partnership Formed to Build Nuclear
Plants,” The New York Times, September 16, 2005, Section C, p. 4.

104

could “continue to do well in nuclear and shouldn’t shy away from their
responsibility.” 257 Unistar would put them at the “fore-front of next-generation nuclear
power.” 258
UniStar Nuclear began ordering critical components for its reactor as early as
2006. According to Michael J. Wallace, then President of the Constellation Operating
Division, one large reactor part already had been forged, and others would be
manufactured, then stored until needed. 259 UniStar also struck a deal for welding and
machining of parts with an Ohio company, BMX Technologies. These investments
would ensure critical parts were on hand and the company would be ready to “move
aggressively for construction of the first EPR (Evolutionary Power Reactor) if everything
else continues to line up correctly.” 260 It was not until July of 2007 that UniStar Nuclear
filed an application with the NRC to build that reactor at the Calvert Cliffs site. Later
that year, Areva submitted materials to begin NRC certification of its U.S. EPR reactor
design. Mayo Shattuck III, Chairman, President, and CEO of Constellation Energy
Group, announced
Constellation Energy strongly believes nuclear power must play a
prominent role in our nation’s energy future, which will be vitally
important in helping America achieve its goals of reducing greenhouse
gas emissions and moving toward greater energy independence . . . This
alliance represents a major accomplishment. It allows us to move
257

Matthew L. Wald, “Even the Utilities Differ Over Whether Nuclear is the Energy Answer,”
The New York Times, August 22, 2006, p. C.1.

258

“Energy Matters, Constellation Energy 2006 Annual Report,” Baltimore, MD: Constellation
Energy, March 2007, p. 12.

259

Matthew L. Wald, “Nuclear Power Venture Orders Crucial Parts for Reactor,” The New York
Times, August 4, 2006, Section C, p. 2.

260

Ibid.

105

forward confidently, leveraging the considerable value of our complementary strengths and operational capabilities, while also maintaining
our highly disciplined, risk-managed and value-driven approach to new
nuclear. 261
His words echoed words that Michael Wallace (President of Constellation Operating
Division) had used a month earlier before the DOE. Both hinted at an interest in nuclear
power not just for the sake of a renaissance, but to help in the battle against greenhouse
gas emissions and global climate change, and to reduce the country’s dependence on
imported oil.
The Constellation 2007 Annual Report reiterated that stand for the sake of
investors.
On the most important environmental issue of our time, climate change,
our company’s policy is unequivocal. We believe it is imperative to slow,
stop and then reverse the growth of greenhouse gas emissions. We believe
nuclear power can and must make a meaningful contribution in the world’s
efforts to deal with threats posed by human influence on climate change.
The result will be a dramatic lessening of our country’s—and the world’s—
reliance on fossil fuels. 262
Fall 2008 was a turbulent time for Constellation. In September, the company
submitted its COL application for a third unit at the Nine Mile Point site. Due to the
worsening credit situation in the U.S. in the summer and fall of 2008, Constellation had
an urgent need for cash. It entered into merger talks with Warren Buffett’s Mid-America
Energy Holdings Co., but instead sold a 49.9 % stake in its nuclear holdings to Electricité

261

“Constellation Energy and EDF Form Joint Venture for Developing Next-Generation Nuclear
Facilities in the United States and Canada,” Constellation Energy Press Release, July 20, 2007,
http://ir.constellation.com/phoenix.zhtml?c=112182&p=irol-news, (accessed July 8, 2008).

262

“Responsible Leadership, Constellation Energy 2007 Annual Report,” Baltimore, MD:
Constellation Energy, April 2008, p. 11.

106

de France. 263 Constellation President Michael Wallace liked EdF because the French
company already felt comfortable with the Areva technology and, “[t]hey never stopped
building.” 264
Despite Constellation’s long-standing commitment to the revival of nuclear power
plant construction in the U.S., President Wallace testified before the DOE in June, 2007,
regarding the importance of loan guarantees to that construction plan.
We at Constellation recognized quite early that the incentives contained
in the Energy Policy Act would be necessary to bring about the new
nuclear renaissance . . . the most important Energy Policy Act incentive
for new nuclear is the Title XVII loan guarantee program, which we view
as indispensable . . . The loan guarantee program is intended to fill [a]
financing gap by creating a non-recourse financing platform whereby
energy companies . . . are allowed to leverage their equity in a manner not
possible without the benefit of the guarantee. 265
The company also revealed that it would not break ground on a new nuclear plant without
the aid of a federal loan guarantee program. 266 If the DOE had the loan guarantee
program in place by the end of 2008, Constellation would move forward with its plans for
construction. “If it doesn’t, we won’t,” according to Wallace. 267 (Although the DOE had
not disclosed its decision about the distribution of the loan guarantees as of the

263

Rebecca Smith, “Buffett Rescues Power Firm for $4.7 Billion,” The Wall Street Journal,
September 19, 2008, p. B.1.
264

Matthew L. Wald, “French-American Venture Plans New Reactors in U.S.,” The New York
Times, July 21, 2007, p. C.4.

265

“LPG Public Meeting,” U.S. Department of Energy, Office of the Chief Financial Officer,
Washington D.C.: Executive Court Reporters, Inc., June 15, 2007, p. 3.

266

“Industry Pushes Nuclear Loan Guarantees,” November 28, 2007,
http://www.fool.com/news/associated-press/2007/11/28/industry-pushes-nuclear-loanguarantees.aspx, (accessed March 19, 2009).
267

Ibid.

107

publication of this thesis, a Reuters news release of February 2008 suggested that
Constellation’s Calvert Cliffs project is one of five still under DOE consideration. 268 )
In short, Constellation Energy has made considerable investments to bring about a
nuclear renaissance in the U.S. and avidly supports nuclear power as a key in helping the
country confront global climate change. However, it likely will take the final step of
building its first reactor only if the company receives federally backed loan guarantees.
4.7 AmerenUE
For AmerenUE, headquartered in St. Louis, Missouri, the ability to recover some
of its costs during the construction was vital to its plan to expand its Callaway Nuclear
Station. The Callaway facility had been completed in 1984 and is the largest single plant
in the AmerenUE fleet—1143 MW(e). The 2005 Annual Report reflected the company’s
pride in its nuclear plant when it reported,
One of the most amazing achievements of our generating fleet was the
refueling and maintenance outage at our Callaway nuclear plant. This
outage included replacing all four steam generators and turbine rotors, in
addition to thousands of maintenance activities, modifications, inspections,
and tests throughout the plant. Despite the massive amount of work, the
outage was completed in only 63 days—a new world record. . .” 269
In 2008, Callaway set another record, this time for the longest “breaker-to-breaker” run
of any plant in the U.S., operating for 520 consecutive days without ever being out of

268

Eileen O’Grady, “Five U.S. Nuclear Plants on DOE Loan Short List,” February 18, 2009,
http://uk.reuters.com/article/idUKTRE51H64R20090218?sp=true, (accessed March 19, 2009).

269

“Geared Up, Ameren 2005 Annual Report,” St. Louis, MO: Ameren.

108

service. 270 Given such accomplishments, it is not surprising that AmerenUE looked to
nuclear power to meet its growing demand for electricity.
AmerenUE grew out of the Union Electric Company, provider of the electric
illumination for the St. Louis World’s Fair in 1904. 271 It now operates 14 power plants
with a generating capacity of over 12,600 MW(e) for customers in Missouri and parts of
Illinois. But, according to Mike Cleary, Communications Executive for AmerenUE,
demand has grown by about 50% since the 1980s when Callaway went on line, and
demand is expected to grow another 30% by 2030. 272 The company has calculated that it
will need new baseload generating capacity on line by 2018 or 2020. Carbon emission
regulations and/or a carbon tax may make coal uneconomical. Fossil fuel prices also tend
to be very volatile. But since the cost of fuel is a very small component of the cost of
nuclear generation, changes in the price of uranium have little impact on nuclear plant
operating costs. “Nuclear is more like a dam in that its costs are mostly in the structure
itself, after that it’s mostly operation and maintenance.” 273 Thus, for AmerenUE, as for
Progress Energy Florida, fuel-related issues made nuclear power a front-runner for
baseload generation.

270

“AmerenUE's Callaway Plant Achieves First "Breaker-to-Breaker" Run, Generating
Continuously for 520 Days,” Ameren Media Release, October 13, 2008,
http://ameren.mediaroom.com/index.php?s=43&item=551, (accessed April 25, 2009).
271

“Ameren History 1902 – 2002,” http://www.ameren.com/centennial/default.htm, (accessed
March 3, 2009).

272

Mike Cleary, Communications Executive, Public and Media Relations, AmerenUE, Telephone
Interview of February 25, 2009.

273

Ibid.

109

The small environmental footprint of a nuclear facility also drew AmerenUE to
nuclear power. According to Cleary, “[t]he spent fuel from Callaway 1’s forty years of
operation would fit into an area the size of a tennis court . . . A coal plant uses hundreds
of train car loads of coal per day. That results in a lot of ash to dispose of . . .” and a
“wind farm would require 280 square miles of land to generate as much electricity as
Callaway 1—which occupies only one square mile.” 274 Unfortunately, Missouri does not
get the steady wind preferred for electric generation, so AmerenUE would need to import
its renewable energy from other states, at high cost to its customers.
A 1976 initiative passed by Missouri voters prevents power plant owners from
recovering any plant development costs while the facilities are under construction. 275
AmerenUE estimated that the higher costs of financing added $1 billion to the cost of its
existing nuclear unit, Callaway 1. In addition, even after Callaway 1 came on line, the
Missouri Public Service Commission cut $165 million from the $639 million the
company sought to recoup from its customers through rate increases. (The Public Service
Commission cited “inefficient, imprudent, unreasonable, or unexplained costs” as the
reason for that decision. 276 ) The company was forced to write off the disallowed costs,
reducing the company’s net income for that year. 277 To avoid similar cost recovery

274

Cleary Interview.

275

Ibid; “Ameren Suspends New Nuclear Plant Plans,” World Nuclear News, April 24, 2009,
http://www.world-nuclear-news.org/print.aspx?id=25101, (accessed March 25, 2009).

276

“Union Electric Wins Appeal for Rate Raise to be Reconsidered,” The Wall Street Journal,
February 28, 1985, p. 1; Bill Richards, “Union Electric Co. Rate Increase Bid is Cut by
Missouri,” The Wall Street Journal, April 3, 1985, p. 1.

277

John Curley, “Union Electric Says it May Post Charge of $250 Million,” The Wall Street
Journal, April 24, 1985, p. 1.

110

issues with the construction of a new nuclear plant, AmerenUE asked the Missouri
legislature to consider a bill that would allow them to recover the financing costs during
the construction period (not the cost of steel or concrete, just the financing costs). 278
Passage of the Construction Work in Progress bill would have resulted in a 1.8 % rate
increase for customers during each of the estimated six years of construction. Without it,
AmerenUE customers would see a massive rate increase once the plant came on line.
Missouri Governor Jay Nixon opposed the bill, calling it “premature for Ameren
‘to saddle’ customers with the cost . . . before regulators have even awarded a permit and
Ameren has made its final decision to build.” 279 On April 23, 2009, AmerenUE CEO
and President Thomas Voss requested the legislative sponsors to withdraw the bill.
As we were moving forward to preserve the option for nuclear energy for
our state, we stressed that we needed financial and regulatory certainty
before we could begin construction. However, the current version of the bill
being debated in the Senate strips the legislation of the very provisions we
needed most to move forward. As a result, AmerenUE is suspending its
efforts to build a nuclear power plant in Missouri . . . without supportive state
energy policies, we believe getting financial backing for these projects is
impossible. 280
AmerenUE had submitted the first and second parts of its loan guarantee
application to the DOE. Unfortunately, the company was not among the five that made

278

Robert D. Hershey, “Utilities Allowed Faster Rate Rises to Pay for Plants,” The New York
Times, March 11, 1983, p. A.1; “Pay-As-You-Build Power,” The New York Times, February 13,
1984, p. A. 20.
279

Kelsey Volkman, “Nixon: Ameren Charging Customers for Plant ‘Premature’,” St. Louis
Business Journal, February 27, 2009,
http://stlouis.bizjournals.com/stlouis/2009/02/23/daily96/html, (accessed March 3, 2009).

280

“AmerenUE Requests Sponsors to Withdraw Missouri Clean and Renewable Energy
Construction Bills in General Assembly,” Ameren Media Release, April 23, 2009,
http://ameren.mediaroom.com/index.php:s=43&item=634&printable, (accessed March 25, 2009).

111

the “short list” for receiving that backing. 281 In the end, for AmerenUE, fuel costs and
environmental concerns may have ignited an interest in building a new nuclear reactor in
Missouri, but concerns over the inability to finance the project doused the flame.
4.8 Dominion Virginia Power
Dominion Virginia Power did not have to petition for cost recovery assistance as
AmerenUE did. Under Virginia law, the company can apply to recover the financing
costs of generation facilities as they are incurred. 282 The law allows Dominion to recover
the costs of the fuel used in the facility—those costs can be passed through to the
customer in the rates charged—and ensures Dominion a competitive return on its equity,
a return guaranteed to be no lower than the average earned by their peer group in the
Southeast. That favorable economic context and a governor who supports coal, nuclear,
and renewable power make Virginia an appealing site for the construction of new
electrical generation facilities.
The need for “home grown” power also makes Virginia attractive for Dominion.
Virginia currently imports about 30 % of its electricity from neighboring states, ranking it
second in the nation, just behind California. Yet the area is home to the Pentagon, two
major military installations, the Washington D.C. suburbs, and businesses like internet
provider AOL and the banks of computers that serve its on-line customers. Dominion

281

John C. Slocum and John H. Reed, “Maximizing U.S. Federal Loan Guarantees for New
Nuclear,” Bulletin of the Atomic Scientists, July 29, 2009, http://www.thebulletin.org/webedition/features/maximizing-us-federal-loan-guarantees-new-nuclear-energy, (accessed October
28, 2009).
282

“There’s More to This Light Switch Than Meets the Eye. Behind it is an Entire Company.
Dominion 2008 Summary Annual Report,” Richmond, VA: Dominion Resources, Inc., 2009, p.
21.

112

estimates that 50 % of the nation’s internet traffic flows through northern Virginia! 283
They need reliable energy.
Dominion analysts have calculated that the area will need an additional 4000 MW
of electricity by the year 2018, including 2000 MW of baseload power. 284 Renewable
sources and conservation cannot provide the electricity whenever a customer flips the
switch. So, to meet about 520 MW of that new baseload demand, the company is looking
to clean coal (carbon sequestration and the conversion of coal to pipeline quality gas) and
woody biomass technologies; the remainder likely will come from a new nuclear
reactor. 285
Dominion operates seven nuclear units at four sites: two at Millstone in
Connecticut; one at Kewaunee, near Green Bay, Wisconsin; two at the Surry facility and
two at North Anna, all in Virginia. 286 Of those, the Surry and North Anna plants were
constructed by Dominion’s predecessor, Virginia Power; the others were purchased in
2000 and 2005. As the company indicated to the DOE in 2007,
A strong commitment to nuclear generation has been, and will remain,
a fundamental attribute of Dominion . . . Dominion has seen six of its
seven nuclear units through the Nuclear Regulatory Commission’s (“NRC’s”)
license extension process. Similarly, Dominion has been in the forefront
of planning for the development of new reactors . . . since 2001, the company
has been systematically working through the issues leading to a decision to

283

Ibid, p. 20; Rick Zuercher, Manager, Public Affairs, Dominion Virginia Power, Telephone
Interview of March 12, 2009.

284

Zuecher; “There’s More to This Light Switch Than Meets the Eye,” p. 20.

285

Zuercher; “Dimensions 2008: A Report to Stakeholders on Values, Goals and Performance,”
Richmond, VA: Dominion Resources, Inc., 2008, p. 13.

286

“Electric Generating Stations,” http://www.dom.com/about/stations/index.jsp, (accessed
January 18, 2009).

113

deploy a new reactor. 287
In September of 2003, Dominion submitted an application to the NRC for an
Early Site Permit (ESP) for two new reactors at the North Anna site. At the time, they
did not specify the desired size for the units (in MW) but did choose the G.E.-Hitachi
ESBWR design. The NRC issued the ESP in November of 2007. Unfortunately, due to
contract issues with G.E.-Hitachi, Dominion re-opened the reactor design process to
competitive bidding in early 2009. 288 The evaluation of the reactor unit designs and
associated proposals continued into the fall of 2009. 289
Dominion continues to evaluate the true cost of constructing and maintaining a
new nuclear power plant. According to Rick Zuercher, Manager of Nuclear Public
Affairs, in the end “economics will determine whether they choose nuclear or some other
option.” 290 The company has submitted an application for federal loan guarantees and
feels “well-positioned” to get one. In comments before the DOE, the Dominion
Resources Legal Department asserted that “[t]hrough all of its planning and preparation,
Dominion has understood the economic reality that a federal loan guarantee is essential to
raise the capital necessary to build this plant . . . Dominion has not made a final decision

287

Zuercher; Eileen O’Grady, “Update 2 – Two US Firms’ Reactor Deals with GE Hitachi Fail,”
January 9, 2009,
http://www.reuters.com/article/rbssUtilitiesMultiline/idUSN0931235920090110, (accessed
March 19, 2009).
289

“New Nuclear in Dominion’s Long Term Plan,” World Nuclear News, September 22, 2009,
http://www.world-nuclear-news.org/NN-New_nuclear_features_in_Dominions_long_term_plan2209097.html, (accessed October 28, 2009).
290

Zuercher.

114

to proceed with North Anna Unit 3, and the uncertainties surrounding the loan guarantee
program represent one of the major reasons for the delay in final decision making.” 291
Thomas Farrell, Chairman, President, and CEO of Dominion Virginia had a similar
message for the PowerGen Conference in December 2008: “Nuclear power is the green
alternative to fossil fuels . . . It potentially complements renewable energy by
compensating for its limitations. Of course, this involves numbers that are downright
scary. The financing of nuclear power has the potential to put more power company
CEOs into forced retirement than any other single subject.”292 (Regrettably, Dominion
was not among the companies on the DOE “short list” to receive federal loan
guarantees. 293 )
The message from the Dominion executives is clear. Despite concerns about
emissions, despite the projected demand growth in the region, and despite Dominion’s
commitment to nuclear power, a new nuclear power plant will not be built unless the
dollars work in their favor.
4.9 PPL (formerly Pennsylvania Power and Light)
PPL has its roots in coal. The company was founded to mine and bring
Pennsylvania coal to Philadelphia. 294 It later moved into electric distribution, joining
291

Thomas F. Farrell, II, “Realistic View of National Energy Challenge is Needed,” Remarks to
the PowerGen Conference, Orlando, FL, December 2, 2008,
http://www.dom.com/about/speeches/120208_print.jsp, (accessed January 6, 2009).

293

Slocum and Reed.

294

“PPL Corporation,” http://0premium.hoovers.com.cals.evergreen.edu/suscribe/co/factsheet.xhtml?ID=rrrjtxyhcyyxyf,
(accessed July 8, 2008).

115

with utilities in New Jersey and Maryland to form a fully integrated power pool. Having
its own coal mines insulated PPL from the fossil fuel price fluctuations of the 1970s, but,
perhaps in response to concerns about air pollution in the Northeast, the company decided
to build its first generating units that did not burn coal—the Susquehanna 1 and 2 nuclear
reactors. 295 The units came on line in the mid-1980s. PPL replaced the high-pressure
turbines in the Susquehanna units in 2003 and applied for operating license renewals in
2006. The NRC approved an increase (by 100 MW(e) each) in the output of the two
reactors in 2008. Although PPL did not expand its nuclear fleet, it has continued to
devote resources to upgrading the facilities.
In the 2006 PPL Annual Report, Jim Miller, Chairman, President, and CEO spoke
of expanding the PPL generating portfolio. 296 At that time, PPL did not have plans to
build a new nuclear plant, due to the “significant uncertainties” of the process (although
one-step licensing had removed some of those uncertainties). Miller did not rule out the
possibility, particularly if PPL could be part of a consortium devoted to licensing and
building nuclear plants. 297 By 2007, both Miller and PPL, had changed their stance.
In the evolving U.S. electricity business, no one can accurately predict
the future. It’s impossible, for example, to precisely forecast the prices
of various fuels, the impact of environmental regulations, actions that
might alter competitive generation markets or technological advances in
electricity generation. Given the uncertainties in this sector, we think the
wise course is to create a wide range of opportunities . . . That’s the reason
we are pursuing a construction and operating license for a potential new
reactor in Pennsylvania. That’s why we are seeking approvals to double
295

“PPL History,” http://pplweb.com/about/our+history/ppl+corporation+timeline.htm, (accessed
March 2, 2009).

296

“Business as Unusual, PPL,” PPL Corporation 2006 Annual Report, Allentown, PA: PPL
Corporation, March 2007.
297

Ibid, p. 7.

116

our hydroelectric generating capacity in Pennsylvania. That’s why we are
planning to spend more than $100 million to develop new renewable energy
projects . . . 298
A new nuclear power facility became one of several options for the future expansion of
PPL.
In a phone interview, a PPL representative (who wished to remain anonymous)
put the interest in nuclear power into a more environmentally oriented context. He
asserted that the popularity of coal-fired generation had diminished over the past ten
years due to its carbon emissions and related climate change issues. Clean coal
technology “isn’t there yet”, and the infrastructure does not yet exist for renewables.
Natural gas could be used for baseload generation, but its prices “are all over the place.”
Nuclear fuel prices have not varied as much as those of either coal or natural gas. Thus,
for PPL, nuclear power then emerges as a good option.
Another factor for PPL has been the acceptance of nuclear power in Pennsylvania,
despite the legacy of Three Mile Island. “Three Mile Island isn’t even on the radar
screen for today’s generation.”299 In addition, PPL has purchased land adjacent to its
Susquehanna facility for potential new nuclear development. “PPL has reactors in the
area already so people are generally positive toward nuclear (77 % in favor of nuclear).
The Susquehanna plant has been a good neighbor.” 300
Still, the cost of new nuclear looms large. PPL has estimated the cost of the new
plant will be about $15 billion, including fuel and financing costs, and assuming a 54298

“Our Formula for Growth? PPL Corporation 2007 Annual Report,” Allentown, PA: PPL
Corporation, April 2008. p. 4.

299

Anonymous, PPL, Telephone Interview of February 26, 2009.

300

Ibid.

117

month construction period. “The production credit for the first 6000 MW has been an
incentive for PPL. Loan guarantees are too . . . They represent a backing for expenditures
which allows for project financing.” 301 Loan guarantees are necessary to secure
financing from Wall Street. PPL also seeks a partner to share the cost: “PPL will not do
it alone.” 302 In a news release of March 25, 2008, CEO Miller was quoted as saying that
the high cost of a new reactor made it risky for PPL “to build a nuclear plant without
partners and help from the federal government.” 303
PPL selected the Areva EPR in part because they expect the French company’s
experience with building reactors of that design will help keep down the cost of
components and construction. 304 The EPR can resist airplane impacts and its size (1600
MW(e)) fits with the company needs. In addition, PPL can visit the construction sites in
Europe to learn from their experiences. Areva has submitted its application to have the
design certified by the NRC. PPL claims it needs to have both its construction and
operating license and the design certification in hand by 2012 for the company to move
forward with new nuclear plant construction. 305
In the end, for PPL, no one factor dominates the decision-making process. A
concern over carbon dioxide emissions from coal, access to production tax credits, loan
301

Ibid.

302

Ibid.

303

“PPL CEO Sees More Fast Growth in Merchant Unit,” March 25, 2008,
http://www.reuters.com/article/companyNews/idUSN25299610120080325, (accessed March 25,
2009).
304

Anonymous, Interview.

305

Ibid; Bernie Woodall, “Update 1 – PPL Applies for Pennsylvania Nuclear Power Reactor,”
October 10, 2008, http://www.reuters.com/article/rbssUtilitiesElectric/idUSN1039915720081010,
(accessed March 10, 2009).

118

guarantees, the costs of building a new nuclear facility (and the ability to find a partner
with whom to share the costs), and the acceptance of a nuclear neighbor all play an
important role in the company’s choice to pursue new nuclear capacity.
4.10 Exelon Corporation
Exelon is a relatively new player in the utility game; founded in 2000 when
Philadelphia based PECO Energy (formerly Philadelphia Electric) purchased Chicago
based Unicom. 306 Philadelphia Electric had built and operated nuclear plants in
Limerick, Pennsylvania and at Peach Bottom, outside Lancaster, Pennsylvania. It joined
forces with British Energy in 1997 to form AmerGen, a company devoted to buying
nuclear plants from companies eager to unload them. AmerGen subsequently acquired
Three Mile Island Unit 1, Oyster Creek in New Jersey, and the Clinton station in Illinois.
When PECO merged with Unicom, it petitioned the NRC to have the AmerGen nuclear
assets integrated into Exelon Nuclear. That approval came in 2009. 307 Exelon
Corporation now operates the third largest nuclear fleet in the world, with 17 reactors at
10 sites in Illinois, Pennsylvania, and New Jersey. 308
For Exelon, having a portfolio of nuclear generating plants has meant more than
economies of scale in purchasing and procurement or operating and maintenance costs.

306

“Exelon History,” http://0premium.hoovers.com.cals.evergreen.edu/subscribe/co/history.xhtml?ID=ffffrrrkkffrxfkrhf,
(accessed January 19, 2009).
307

“Exelon Takes Direct Control of Clinton Nuclear Plant,” Herald & Review, January 9, 2009,
http://uaelp.pennnet.com/news/print_screen.cfm?NewsID=172328, (accessed January 18, 2009).

308

“Operating Clean, Safe, Reliable and Affordable Nuclear Energy Plants,” Exelon Nuclear,
www.exeloncorp.com, (accessed March 4, 2009); “Exelon’s Proposed Nuclear Generating
Station in Victoria County,” October 27, 2008, www.ExelonNuclearTexas.com, (accessed March
4, 2009).

119

Craig Nesbitt, Exelon Communications Officer asserted, “We’ve gotten pretty good at
managing a fleet of nuclear plants . . . We have a management model that is published
and proven.” 309 Bruce Paulsen, spokesman for the Clinton station agreed: “Exelon has
become known worldwide for its efficiencies and its good processes for safely running
nuclear plants.” 310
Exelon opted to first test the NRC’s new permitting and licensing process with an
application for an ESP to build another unit at the Clinton site. The NRC received the
application in September of 2003 but it took over three years for all of the agency
reviews, public hearings, and inspections to be completed. The permit was issued March
15, 2007. 311 However, by that time, Exelon no longer had plans to build there.
According to Marilyn Kray, Exelon Vice President, “Certain conditions would have to
fall into place before Exelon would consider building a plant: a workable solution to the
spent fuel disposal problem; community acceptance; the right reactor technology; and the
economics must be favorable.” 312
Despite Kray’s earlier comments about spent fuel disposal and the lack of
progress on a national solution to the nuclear waste issue, in December of 2007 Exelon
announced plans to build a new nuclear plant in Victoria County, Texas. 313 The
309

Richard Stavros, “A Nuclear Liability?” Business & Money,
http://www.pur.com/pubs/4495.cfm, (accessed January 18, 2009).

310

“Exelon Takes Direct Control of Clinton Nuclear Plant.”

311

Tom Doggett, “Update 1 – U.S. OKs Early Site Permit for Nuclear Power Plant,” March 8,
2007, http://www.reuterscom/article/companyNewsAndPR/idUSN0834009020070308, (accessed
March 19, 2009).

312

Ibid.

313

“Exelon to Apply or Nuclear Plant License in Texas,” December 18, 2009,
http://www.reuters..com/article/governmentFilingsNews/idUSN1849237320071218, (accessed

120

company also signed a deal with G.E.-Hitachi for the ultra-large forgings, reactor
pressure vessel, and steam turbine fabrication. 314 The formal application to the NRC
followed in September 2008. Shortly thereafter, in November of 2008, Exelon reversed
its decision to build the G.E-Hitachi ESBWR. World Nuclear News reported that
“Exelon’s change of mind has been driven by the need to secure federal loan guarantees,
which the company says are essential for financing the project. ‘We are seeking
improved eligibility for federal guarantees, which is critical to the advancement of the
project’ said Exelon Vice President for New Plant Development Thomas O’Neill.” 315
Since the speed at which the technology could be commercialized was one of the DOE
selection criteria for the loan guarantee program, Exelon executives felt the company had
a better chance of receiving the government backing using a reactor whose design was
farther along in the NRC certification process. 316 Craig Nesbitt commented that any
decision to build a new nuclear reactor would be based on the availability of financing. 317
Exelon also made the news in the fall of 2008 with a proposed takeover of NRG
Energy. In October, Exelon announced plans to acquire all outstanding shares of NRG

March 19, 2009); “Exelon Applies for Nuclear Permits,” UPI.com, September 4, 2008,

http://www.upi.com/Science_News/Resource-Wars/2008/09/04/Exelon-applies-fornuclear-permits/UPI-87171220538811/, (accessed January 20, 2009).
314

“Exelon Nuclear Signs Agreement with GE Hitachi for Major Components for Two ESBWR
Nuclear Reactors in Texas,” December 11, 2007, http://www.allbusiness.com/energyutilities/utilities-industry-electric-power-power/324762-1.html, (accessed January 20, 2009).
315

“Exelon Changes Mind Over Design of New Reactor,” World Nuclear News, November 25,
2008, http://www.world-nuclear-news.org/print.aspx?id=23724, (accessed January 18, 2009).

316

Ibid; Eileen O’Grady, “Exelon Seeks New Nuclear Design for Texas Project,” November 24,
2008, http://www.reuters.com/article/americasDealsNews/idUSTRE4AN8EW2001124, (accessed
March 19, 2009).
317

Ibid.

121

common stock in an all-stock transaction. 318 NRG management rejected the offer, and
Exelon took a stock exchange offer directly to the shareholders. By mid-March, the
Exelon offer had received support from a majority of the NRG shareholders. Exelon
announced that should it take over NRG Energy, it would build the two reactors proposed
for the NRG South Texas Project site and would delay building in Victoria County.
“That’s not to say we wouldn’t build a site in Victoria . . . It’s impossible to predict how
long that would push back Victoria’s plant build. It might not mean anything, but it
might mean a lot.”319 In an interesting twist, about the same time, the press reported that
the South Texas Project has made the “short list” for DOE loan guarantees whereas the
Victoria County project has not. 320 Together, those facts would support Exelon’s
contention that the loan guarantees were a decisive factor in new reactor construction for
the company. Unfortunately for Exelon, however, during the summer 2009, NRG
shareholders expressed concern they were not being adequately compensated and rejected
the proposed expansion of the NRG board to accommodate Exelon representatives. 321
The deal fell through, leaving Exelon without a candidate for federal loan guarantees.

318

“Exelon Gains Ground in Bid to Take Over NRG; Majority of Shares Tendered; Fight Now is
for Board Seats,” The Chicago Tribune, February 27, 2009,
http://www.tmcnet.com/usubmit/2009/02/27/4018793.htm, (accessed March 4, 2009).

319

“Exelon Moves Forward: NRG Bid Supported by Shareholders, but Offer’s Terms Still not
Agreed Upon,” Victoria Advocate (TX), February 27, 2009,
http://www.istockanalyst.com/article/viewiStockNews/articleid/3075873, (accessed March 4,
2009).
320

Jim Fuquay, “EFH Project Said to be on Loan Short List,” Fort Worth Star-Telegram (TX),
February 19, 2009, p. C02; O’Grady, November 24, 2008.

321

Mark Peters, “NRG Holders Balk; Exelon Drops Bid,” The Wall Street Journal, July 23, 2009,
p. M4.

122

Did concern about the environment or global warming affect Exelon’s interest in
new nuclear reactor construction? Not to a great degree. Exelon launched “Exelon 2020:
A Low-Carbon Roadmap” in 2008. 322 “Exelon 2020” outlines the company’s approach
to lowering carbon dioxide emissions within the corporation and among its customers and
suppliers. In that document, Exelon brags that it already had a carbon footprint smaller
than that of its competitors as a result of its large nuclear fleet. “Exelon’s CO2 emissions
per unit of electricity generated are almost 90% below the national average for our
industry.” 323 Exelon is committed to making its existing nuclear facilities as safe and
reliable as possible: “Over the next five years, Exelon Generation will invest $700
million - $900 million annually in equipment reliability, life extension and enhanced
generation at existing plants. By completing the re-licensing of all its nuclear facilities,
Exelon can provide nearly 17,000 MW of virtually zero-carbon electricity over the next
20-plus years.” 324 Although the company continues to explore its options, “Exelon will
not commit to building new nuclear plants . . . until we are satisfied that our conditions
for safety, regulatory stability, bipartisan federal, state, and local support, spent fuel
management and cost have been met.” 325 Exelon has the luxury of operating 17 non-

322

“Exelon Unveils Roadmap to Eliminate Equivalent of Current Annual Carbon Footprint by
2020,” Exelon Press Release, July 15, 2009, http://phx.corporateir.net/phoenix.zhtml?c=124298&p=irol-newsArticle&ID=1175027&highlight=, (accessed
January 18, 2009); Matthew L. Wald, “To Set Tone, Exelon Plans Huge Cut in Emissions,” The
New York Times, July 15, 2009.
323

“Exelon 2020: A Low Carbon Roadmap,”
http://www.exeloncorp.com/NR/rdonlyres/6BF790FC-6ADB-422D-A7A536F3776748CC/0/080716Exelon2020_A_Low_Carbon_Roadmap.pdf, (accessed January 18,
2009), p. 6.
324

Ibid, p. 18.

325

Ibid, p. 19.

123

CO2-emitting reactors at its ten sites. It can wait until conditions are right to make further
investments.
4.11 What Have We Learned?
As explained at the beginning of this chapter, the decision to submit an
application to build a new nuclear reactor emerged from the confluence of a number of
factors: (1) Increasing demand for electricity and a need for greater baseload generation
capacity, (2) Concerns about greenhouse gas emissions and potential regulation or
taxation, increasing demand for electricity, (3) Questions about the availability of
alternative fuel sources and the volatility of fuel pricing, (4) The availability of financial
backing for new nuclear construction. The previous sections detailed the importance of
those factors to each of the ten companies that were part of this study. This section takes
a step back to look at the information as part of a larger picture of new nuclear
construction.
Table 3 summarizes all of the data gathered through the interviews and from
media sources. (Note: The X’s in the table indicate reasons discussed during the
interviews whereas the M’s show the factors mentioned in the various media sources.)

124

Other

Nuclear Experience

Fuel-Related

Regulatory

Meeting Demand

Past Experience with
Nuclear

Fuel Usage/Costs

X
M

Need for Fuel Diversity

Interveiw
Media
Progress Energy Florida
Interveiw
Media
Tennessee Valley Authority
Interveiw
Media
Constellation Energy
Media
AmerenUE
Interveiw
Media
Dominion Virginia Power
Interveiw
Media
PPL
Interveiw
Media
Exelon
Media

Renewables/Efficiency
Aren't Enough

X
M

Demand/Need for more
baseload generation

One Step Licensing

Interveiw
Media

Price Anderson
Insurance Backing

Risk Insurance

Ability to Recoup Costs
during Construction

Production Tax Credits

Availability of Loan
Guarantees

Financing

Energy Security
National Energy Security

Environmental
Climate Change /
Emissions
Concerns/Environmental
Media

NRG Energy
M

X
M

Entergy
X

Duke Energy

X
M

not a factor
M
X
M
M

X
M

M
X

not a factor

X
M
X

X
M

X = Information obtained during an interview

X
M

M
X

X
M

M
X
M

X
M

M = Information from media sources

Table 3: Factors Affecting Decisions to Apply to Build New Nuclear Power Plants
as Reported in Interviews and the Media

125

The different numbers of Xs and Ms in the table indicate dissimilarities between
the factors deemed important by the media versus the companies themselves. For
example, as seen by the large number of Ms in the columns, the media focused on
environmental factors and potential carbon taxes or cap and trade programs, on the need
to meet customer demand through increased baseload generation, and on a company’s
prior experience with nuclear power. On the other hand, the companies talked about the
importance of the Price Anderson Insurance to the industry and about the role the change
to the one-step licensing process had in their decision to submit a COL application to the
NRC. The media paid attention to external factors readily visible to and easily
understood by the general public, whereas the companies mentioned reasons that
involved the process and context currently faced within the industry.
Interestingly, although the Bush/Cheney administration often put national energy
security at the core of their policies and actions, that potential driver of the interest in new
nuclear power plants received little attention by either the media or the companies
applying to build new plants (See “National Energy Policy Report” as well as the
statement of D. Spurgeon, Office of Nuclear Energy, Department of Energy, in
“Implementation of the Provisions of the Energy Policy Act of 2005,” p. 54 ff). 326
The investment community had expressed concerns about the potential delays in
bringing new reactors on line:
326

“National Energy Policy Report of the National Energy Policy Development Group: Reliable,
Affordable, and Environmentally Sound Energy for America’s Future,” Washington D.C.: U.S.
Government Printing Office, May 2001; “Implementation of the Provisions of the Energy Policy
Act of 2005,” Hearings Before the Committee on Energy and Natural Resources of the United
States Senate, May 15, 2006, May 22, 2006, June 12, 2006, June 9, 2006, Washington D.C.: U.S.
Government Printing Office, 2006.

126

The industry and financial community remember that a number of the
existing plants that received their operating licenses in the 1980s and
1990s experienced delays due to regulatory or licensing issues that arose
after most or all of the capital investment in the plant had been made.
These delays were caused by a number of factors, including construction
issues, quality assurance weaknesses, coordination issues between plant
design and construction work, changing requirements, and the mechanics
of the two-stage licensing process, which resulted in litigation at the preoperation stage. 327
Yet Table 3 shows that the Delay Risk Insurance did not factor highly in utility or nuclear
investment companies’ decisions. These results indicate that Delay Risk Insurance may
not influence the initial decision to build a new nuclear facility, but it may be important
in attracting external financing for a nuclear plant once that decision has been made. The
results also suggest the COL applicants feel confident that the new licensing process and
changes implemented since the first round of reactor construction will indeed keep their
projects on schedule and delay insurance will be unnecessary.
The Production Tax Credit also had been touted as necessary to lure capital
investment in new nuclear power and to put nuclear on equal footing with renewable
energy sources. In his statement before the Committee on Energy and Natural Resources
of the U.S. Senate, Marvin Fertel, President and Chief Nuclear Officer of the Nuclear
Energy Institute had stated that “The $18-per-megawatt-hour production tax credit
provided . . . is an important step toward making investment in the first few new nuclear
plants attractive to the private sector. This tax credit is comparable to that provided for
other sources of new, emission-free electricity generation.” 328 Yet, during the interviews,
only PPL indicated that the availability of Production Tax Credits played a role in their
327

328

Ibid, p. 27.

127

decision to undertake a new nuclear construction project. This may be because large
amounts of capital will be needed prior to and during the construction phase whereas a
Production Tax Credit would not take effect until after the unit came on line and began
producing electricity—well after the bulk of the funds had been expended. The promise
of a “rebate” years in the future did not seem to be motivating factor in the new nuclear
decision.
Unlike Delay Risk Insurance and Production Tax Credits, Federal Loan
Guarantees did factor highly into decisions to apply for licenses to build new nuclear
reactors. The loan guarantees assure lenders that the money lent will indeed be repaid,
and also ensure that the companies undertaking these capital intensive, multi-year
projects will continue as going concerns even if the unthinkable happens and the reactor
unit never produces electricity. They will not suffer the fate of the public utility, Long
Island Lighting Company (LILCO), whose Shoreham Nuclear Power Plant received a
conditional, lower power, license but failed to receive its full power operating license
from the NRC. 329 The state of New York and its Long Island Power Authority (LIPA)
took control of Shoreham in 1989, closed it, and decommissioned the facility. LILCO
struggled to repay its debt through annual rate increases (its rates rose to the highest
levels in the continental U.S. by the mid-1990s), but eventually LILCO sold its

329

“Shoreham Nuclear,” Exponent Engineering and Scientific Consulting, 2008,
http://www.exponent.com/Diesel-Generator-Stress-Evaluating-Failures-in-the-Shoreham-Planton-Long-Island/, (accessed October 29, 2009); “Shoreham,” August 9, 2007,
http://www.nukeworker.com/nuke_facilities/North_America/usa/NRC_Facilities/Region_1/shore
ham/index.shtml, (accessed October 29, 2009).

128

transmission and distribution system and transferred its debt to LIPA, and merged its
remaining assets with the Brooklyn Union Gas Company. 330 LILCO was no more.
In sum, looking at the data as a whole, the primary factors behind companies’
decision to submit a COL application to the NRC are:
1. Environmental Concerns (emissions, potential carbon taxes), mentioned for nine
of the companies in the media and by six of the company representatives;
2. Meeting Customer Demand through Increased Baseload Generation, with seven
media and five company references;
3. Fuel Usage and Costs, brought up for six companies in the media and by six of
the companies representatives interviewed; and
4. The Availability of Federal Loan Guarantees, mentioned in the media for five
companies and by four company representatives.

330

Bruce Lambert, “Lilco Merger Receives Conditional Support,” The New York Times, April 11,
1997, p. B.8; Richard Perez-Pena, “Lilco’s Hard Journey,” The New York Times, July 21, 1997, p.
B.4.

129

5.0 What Do These Results Tell Us?
Chapter 1 of this thesis asked the question: What factor or combination of factors
has motivated the interest in building new nuclear power facilities in the United States?
The scientific community has stressed the need to reduce the greenhouse gas emissions
implicated in anthropogenic global warming—has that driven the spate of applications
for construction and operating licenses for nuclear reactors? Unrest in the Middle East
and the potential for a disruption in supply of Middle East oil have led to concerns about
supplies and cost of oil and thus national security. Might that have spurred the
applications? Or are the utility companies and nuclear plant operators merely responding
to increased customer demand for baseload electricity? Concerns over greenhouse gas
emissions could raise interest in renewable energy options, the situation in the Middle
East might motivate oil exploration closer to home, and increased demand could generate
a new look at hydropower or coal. Why then have companies submitted applications to
build new nuclear power plants?
This research demonstrated that environmental concerns, customer demand,
anxieties about the availability and prices of fuel, and the availability of Federal Loan
Guarantees or CWIP financing all contribute to the decision to submit an application to
construct and operate a new nuclear power plant in the United States. There was not just
one factor behind the companies’ choice; it took a blend of several things to prompt the
decision.
Now, how do we make sense of the seemingly disparate combination of factors
summarized in Table 3 of Chapter 4?

130

Economic theories of supply and demand could explain when a utility company
would choose to add baseload capacity to meet expected future demand, or at what point
they would choose to build rather than buy power from neighboring utilities. 331 Very few
substitutes exist for electricity from the grid. Unless a company or residence can
generate its own supply (through installed photovoltaic panels, for example), the
electricity must come from the electric grid and big suppliers like Duke Energy, NRG, or
Exelon. That lack of substitutes also means that customers will continue to use electricity
even if the price increases. Some customers may reduce their consumption if the price
climbs too high, but most will grumble about their bills and continue using electricity as
before. Eventually, the neighboring utilities will not be able to supply all of the excess
electricity needed. New capacity will need to be added. A utility company probably
would construct a new facility when the increase in projected electrical demand just
about equaled the capacity of the new plant or when the cost of construction was less than
or equal to the price paid to meet customer electrical needs. Unfortunately, economic
supply and demand models do not explain why a utility would undertake construction of
a new nuclear unit or plant and not add a coal or natural gas plant instead.
Strategic theories of barriers to entry suggest there are factors unique to an
industry that make it hard for outsiders to gain a foothold within it (see, for example, Yip;
Samuelson and Nordhaus) 332 . Barriers to entry can include product branding; legal

331

Karl E. Case, and Ray C. Fair, Principles of Microeconomics, Sixth Edition, Upper Saddle
River, NJ: Prentice Hall, 2002; Paul A. Samuelson and William D. Nordhaus, Economics,
Seventeenth Edition, New York, NY: McGraw-Hill, 2001.
332

George Yip, “Diversification Entry: Internal Development Versus Acquisition,” Strategic
Management Journal, Vol. 3, No. 4, October – December 1982, pp. 331 – 345; Samuelson and
Nordhaus.

131

restrictions, tariffs, and patents; or access to raw materials. For the nuclear industry,
those factors could include the length of time it takes to build and license a new
commercial nuclear power plant, the high capital costs associated with that construction,
or the steep learning curve and long time it takes for a reactor unit to reach a 90%
operating capacity (Recall Figure 4). Barriers to entry could explain why a company like
Constellation would choose to purchase existing nuclear power plants in order to get into
the nuclear business. Constellation did not have to wait for years before its plants would
begin producing electricity, as it would have had it started from scratch. It did not have
to endure several years of low capacity factors as it ironed out the kinks in its new
systems or trained new personnel. Purchasing an existing facility also ensured that the
community accepted (or least tolerated) having a nuclear power plant in their back
yard—they would not face the protests and legal battles that delayed the completion of
many of the early nuclear power plants. (PPL chose to expand its existing Susquehannah
site because it “has reactors in the area already so people are generally positive toward
nuclear (77 % in favor of nuclear). The Susquehannah plant has been a good neighbor.
Thus, nuclear is a good option.” 333 )
The theory of barriers to entry also clarifies why the utilities that have applied to
build a new nuclear plant are ones that have one or more existing nuclear plants in their
portfolios: They have the requisite experience with nuclear power plant operation. But
barriers to entry do not explain why a utility like Duke Energy, which already owns and
operates both nuclear and fossil fuel-based electric generating plants, would choose to

333

Anonymous, PPL.

132

build a new nuclear plant and not use those funds to invest in an advanced, combined
cycle coal facility or in other renewable technologies.
First mover advantages suggest that the initial investors in a new technology, new
product, or new business will benefit more than those who come later—in the case of
new nuclear construction, the first movers would receive a share of the limited number of
federal loan guarantees available. 334 The first movers would submit their applications
early, and thus would have time to revise them or strengthen their case for the federal
support. First mover advantages also help us understand why companies selected the
AP1000 reactor design (which had received initial NRC certification in January 2006)
over the unlicensed Areva EPR, and why some have changed their chosen reactor design,
moving away from the GE-Hitachi Economic Simplified Boiling Water Reactor, to make
sure the reactor design is one that, according to the DOE, “can be commercialized more
quickly” and thus meets the criteria for loan guarantees. But if the first mover advantages
of loan guarantees are so important, why then did a company like Progress Energy
Florida withdraw itself from the loan guarantee competition? Likewise, why is the TVA
proceeding down the path of new nuclear without access to the Federal Loan Guarantee
program?
The literature on corporate volunteerism provides insight into why utilities would
choose to invest in baseload capacity that does not rely on fossil fuels. The Kyoto
Protocol, Regional Greenhouse Gas Initiative (RGGI), and the Western Climate Initiative
all set caps on the levels of emissions of carbon dioxide and other greenhouse gases.

334

Marvin B. Lieberman and David B. Montgomery, “First Mover Advantages,” Strategic
Management Journal, Vol. 9, Special Issue: Strategy Content Research, Summer 1988, pp. 41 58.

133

Some countries, companies, and states may voluntarily sign onto such initiatives to
preempt more stringent regulation in the future. 335 Others may choose to reduce
emissions in response to consumers’ and investors’ calls for “green energy.” For
example, Rita Sipe of Duke Energy acknowledged that Duke’s interest in new nuclear
stemmed in part from the possibility of carbon legislation. Progress Energy Florida
listened to its customers’ appeals for increased energy efficiency and more wind and
solar power. However, since neither wind nor solar energy can yet provide baseload
electrical generation, Progress Energy looked to non-polluting nuclear instead. Still,
without other factors such as increased demand and the access to loans or CWIP
financing, neither Duke nor Progress Energy would have considered building a new
nuclear facility that provides 1200 to 1600 MW(e) of baseload capacity.
To find one coherent theory that encompasses a utility/investment company’s
environmental concerns, their anxieties about the availability and prices of fuel, the
availability of Federal Loan Guarantees or CWIP financing, and customer demand, we
turn to Political Ecology.
The term Political Ecology first emerged in the 1970s as people became
increasingly aware of how highly politicized the natural environment had become. 336
Some traced its origins to political economy and the teachings of (1) Adam Smith (and
his ideas of using the fruits of ones labor to generate revenue and of the progress of
nations from agricultural states to industrial powerhouses); (2) Thomas Malthus (who
335

Eric Welch, Allan Mazur, and Stuart Bretschneider, “Voluntary Behavior by Electric Utilities:
Levels of Adoption and Contribution of the Climate Challenge Program to the Reduction of
Carbon Dioxide,” Journal of Policy Analysis and Management, Vol. 19, No. 3, Summer 2000, p.
410.

336

Roderick P. Neumann, Making Political Ecology, Oxford University Press, 2005, p. 33.

134

believed that population growth and diminishing food supplies would lead to the
downfall of society); and (3) Karl Marx (who looked at the relationships between
property ownership and the productive activity of a state). Others felt its roots lay in the
field of geography and the tensions between human environment and its structures and
governing principles on the one hand and the natural environment on the other.
co*ckburn and Ridgeway, in their 1979 anthology, Political Ecology, defined
Political Ecology as a “way of describing the intentions of radical movements in the
United States, in Western Europe, and in other advanced industrial countries.” 337
Regarding the activism that had grown up to oppose nuclear power plant construction,
they wrote
. . . such an argument [against nuclear power] must confront issues of the
economy, of health, of agriculture, of land use, of technology. The argument must present rigorous rather than rhetorical analysis of the energy
industry; it must do more than gesture toward alternative energy options.
And because we live in the real world of corporate interest, federal and
local politics, the ecological argument must by definition be political too. 338
They later continued:
While the issue of energy was the central question, more profound was the
gradual realization of all the various groups within the movement broadly
sketched above that the word “ecology” implies the indivisibility of total
systems, and that all their disparate concerns were connected . . . Hence has
arisen the term “political ecology”. . . 339

337

Alexander co*ckburn, and James Ridgeway, Political Ecology, New York, NY: Times Books,
1979, p. 3.

338

Ibid, p. 4.

339

Ibid, p. 6.

135

Unfortunately, co*ckburn and Ridgeway did not attempt to intertwine those different
threads in their book; rather, they included excerpts from books and articles written
against nuclear power and favoring alternative energy options.
In the 1980s, American and British Political Ecology research sought to
understand the relationship between the access to and control over resources and
environmental changes occurring in less-developed nations. 340 French Political
Ecologists also focused on control issues. They saw society as trying to distance itself
from nature and the forces of natural elements by increasingly taking command of
production processes and by increasing consumption. 341
The inaugural volume of the Journal of Political Ecology appeared in 1994. In
their introduction to that issue, Greenberg and Park proposed that Political Ecology had
grown out of the questions asked by social scientists about the relationships between
human society and a “humanized” nature (that is, one that has been significantly affected
by human activities of farming, mining, domesticating animals, building cities and roads,
and the like). 342 They described Political Ecology as an exploration of the conflicts
between people, their productive activities, and nature, and the influence of cultural and
political activity on all three. That first journal set the stage for the diversity of subject
matter that has become “Political Ecology.” It included articles dealing with water

340

Nuemann, p. 5.

341

Brigit Müller, “Still Feeding the World? The Political Ecology of Canadian Prairie Farmers,”
Anthropologica, Vol. 50, 2008, p. 391.

342

James B. Greenberg and Thomas K. Park, “Political Ecology,” Journal of Political Ecology,
Vol. 1, No. 1, 1994, p. 1.

136

conservation, the complicated issues tied to man-made borders, and the impact of
externally imposed regulations on shrimp fisheries.
Dr. John Perkins studied the “Green Revolution” in agriculture using a Political
Ecology framework in his book Geopolitics and the Green Revolution: Wheat, Genes,
and the Cold War, published in 1997. 343 He examined the history of plant-breeding and
the strategic and social decisions made in times of peace and war. He looked at the
development of high yield varieties of wheat and rice and the impact the new strains had
on the dependency relationships between developed and developing nations. He also
explored some of the unintended negative consequences of intensified farming. In doing
so he followed one of the basic premises of Political Ecology--that environmental
problems cannot be understood without consideration of the historical, political,
economic, social, and biophysical contexts in which they are embedded (Neumann, pp. 9
and 41). 344
In his book, Perkins demonstrated how technology mediated between human
needs and wants and the natural environment/natural resources (See Figure 11).

Natural Resources and
The Environment

Technology

Human Wants
and Needs

Figure 11: Political Ecology Model of Agricultural Developments
(From Perkins, p. 5)

343

John H. Perkins, Geopolitics and the Green Revolution: Wheat, Genes, and the Cold War,
New York, NY: Oxford University Press, 1997.

344

Neumann, pp. 9 and 41.

137

The first set of double arrows in the model suggest not only that the type of natural
resources being exploited and the environmental context affect the type of technology
adopted, but also that changes in technology can influence the environment. For
example, farmers in the American West require a predictable source of water so their
crops will flourish. When natural rainfall and local streams have not met their needs,
they have diverted water from rivers using large dams and series of canals, and watered
the crops using mobile overhead irrigation systems. 345 Unfortunately, those extension
irrigation networks have wreaked havoc on the amount of water available for fish
populations, navigation, and other uses of the river (Harden). 346
Technology also influences and is influenced by human wants and needs. Again
using western farming as an example, the ability to grow crops locally meant that more
people could find a food supply and settle in the area. Population increases resulted in
larger farms producing an increasing variety of crops, not just those particularly suited to
the climate, but also ones the new settlers had brought with them from other parts of the
country and the world. The advent of refrigerated rail cars and trucks meant that produce
could be shipped longer distances, opening up new markets. The increased demand led
to the establishment of larger farms and the development of new varieties of crops that
would travel well over long distances.
A Political Ecology framework like the one used by Perkins can be adapted for
understanding the interplay of the many reasons for submitting a COL application to the

345

Marc Reisner, Cadillac Desert: The American West and Its Disappearing Water, New York,
NY: Penguin Books, 1993.

346

Blaine Harden, A River Lost: The Life and Death of the Columbia, New York, NY: W. W.
Norton, 1996.

138

NRC to build a new nuclear reactor. First, in the case of commercial nuclear reactors and
other energy technologies, the natural resources/environment of interest would include
the concerns over supplies of fuels to power electrical generation (such as the dwindling
supply of natural gas and its price fluctuations, or the environmental destruction
associated with coal mining) and the carbon dioxide emissions linked to global climate
change. The human want/need to be satisfied would be the almost unlimited access to
electrical power that drives modern life. People want their lights to turn on, their heaters
to blow warm air, their coffee makers to brew, and their washing machines to agitate
when they flip the switches. Finally, the technology that provides that electricity would
be a turbine generator, fired by coal, hydropower, fossil fuels, or nuclear reactions. Thus,
utility companies would examine their various technology options to meet increased
electrical demand and as their concerns grow over potential carbon taxes or cap and trade
programs.
Perkins’ model needs to be modified to include the one other factor that drives the
decision to build a new nuclear power plant: The availability of financial resources and
capital investment. The interviews and media sources reviewed for this thesis point to
loan guarantees and access to CWIP (construction-work-in-progress) financing as crucial
for new nuclear construction. Recall the words of Paul Hinnenkamp of Entergy Nuclear:
“[L]oan guarantees are essential to reduce the financial risk of new nuclear deployment
and enable Entergy to leverage the large investment required . . . We cannot take on the
debt required to finance a new build without an effective loan guarantee program” (“LPG
Public Meeting,” p. 57). 347 Remember too that AmerenUE withdrew their application
347

“LPG Public Meeting,” p. 57.

139

when it appeared certain that the Missouri legislature would deny them the CWIP
financing they had requested. The new model therefore adds Capital
Investment/Financing to the original Perkins model:

Natural Resources and
The Environment

Technology

Human Wants
and Needs

Capital Investment/Financing
Figure 12: The Political Ecology of New Commercial Nuclear Power Plants

Unlike the arrows linking technology to human wants and needs, and natural resources,
the arrow between the technology choice and Capital Investment/Financing has been
drawn with a single head, indicating a one-way flow of capital. Some might argue that
the arrow should be two-headed since the companies involved could influence the
availability of the capital from the local or federal government through their political
contributions. For example, in 2005, the year the Energy Policy Act was passed,
renewing the Price Anderson Indemnity Insurance program and outlining the Federal
Loan Guarantee program for new nuclear reactors, Duke Energy spent over $2 million
lobbying the federal government. 348 The electric utility portion of Entergy paid out over
$1.5 million in lobbying, and Areva, the French company hoping to certify the U.S.
Evolutionary Power Reactor (EPR), spent over $700,000. 349 Although those figures may

348

“Lobbying, Duke Energy,”
http://www.opensecrets.org/lobby/clientsum.php?year=2005&lname=Duke+Energy&id=,
(accessed September 19, 2009).

349

“Lobbying, Entergy,”
http://www.opensecrets.org/lobby/clientsum.php?year=2005&lname=Entergy+Corp&id=,
(accessed September 19, 2009); “Lobbying, AREVA Group,”

140

pale compared to those of the “heavy hitters” like the United Auto Workers, the National
Rifle Association, Microsoft, or the Boeing Company, they do indicate intent to influence
members of Congress and their positions on key issues. Still, such contributions are
meant to influence ideas and votes, and cannot be considered the same type of investment
as loans, which return interest to the lender, or outlays for physical structures, which may
generate income during their lifetime or a profit when sold. For these reasons, the arrow
is drawn in one direction.
Since much of current Political Ecology deals with the control over access to and
use of environmental resources, this thesis discussion would be incomplete without an
examination of the various ways control manifests itself in the model of the decision to
submit an application to build a new nuclear power plant.
First, there is the power exercised by the federal government. The Bush/Cheney
administration characterized uninterrupted access to a diversity of fuel supplies as an
issue of national security. Thus, their National Energy Policy focused on increasing
domestic supplies of energy. It advocated an increased use of renewable sources
(including methane from landfills, wind, and biomass), research into clean coal
technology, opening of the Alaska National Wildlife Refuge (ANWR) to oil exploration,
and the expansion of nuclear energy in the United States. 350 The Bush/Cheney
administration primarily relied upon federal funding and legislation to control use of the
associated natural resources. For example, the Energy Policy Act (EPAct) of 2005
provided billions of dollars in production tax credits, subsidies, and loan guarantees for
http://www.opensecrets.org/lobby/clientsum.php?year=2005&lname=AREVA+Group&id=,
(accessed September 19, 2009).
350

“National Energy Policy,” p. xiv.

141

the energy projects favored by that administration, including those outlined earlier for
new nuclear power plants. 351 The 2009 Senate version of a clean energy bill would
augment those provisions with investment tax credits, additional loan guarantees, and
federally financed training for nuclear workers.352 Those inducements provided a clear
signal to researchers, the investment community, and to the utility companies themselves
where they should be putting their own money, efforts, and attention.
Likewise, by insisting on Federal loan guarantees before agreeing to provide
financing for new nuclear power plants, Wall Street investors control the utility
companies’ access to actual funding. Regardless of a company’s cash flow position or
historical record with nuclear power plant operations, regardless of its ability to
demonstrate the need for a new baseload facility or its outlook for their future, the
company would not get a loan from outside investors without government backing.
Power over access to the natural resource involved in nuclear power generation—
uranium--has caused a stir in recent years. With the renewed interest in nuclear power
and increases in the price of uranium during the 2000s came a renewed interest in mining
the domestic lodes of that ore. According to the Environmental Working Group, new
uranium mining claims on federal lands in just four states (Colorado, Wyoming, Utah and
New Mexico) jumped from just over 4000 in 2004 to more than 32,000 in 2006 . 353 In

351

“Title XVII – Incentives for Innovative Technologies,” Public Law 109 – 58, August 8, 2005,
http://www.lgprogram.energy.gov/EPA2005TitleXVII.pdf, (accessed October 27, 2009).

352

Mufson, October 28, 2009; “Can We Afford More Subsidies for Nuclear Power?” Union of
Concerned Scientists, October 20, 2009, http://www.ucsusa.org/news/press_release/can-weafford-more-subsidies-0296.html, (accessed November 2, 2009).
353

“Mining Law Threatens Grand Canyon, Other National Treasures,” August 16, 2007,
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142

addition, in February 2008, without the customary formal environmental review, the U.S.
Forest Service approved a permit for a British company to explore for uranium just
outside Grand Canyon National Park. 354 These claims are covered by an 1872 mining
law that permits companies to stake an exclusive claim for as little as $1 per acre, pay no
royalties, and receive a tax break for up to 22 % of the metals ore they extract. 355 Despite
concerns about the toxic water pollution and environmental impacts of uranium mining as
expressed by the Sierra Club, the Center for Biological Diversity and others, the existing
law gives the mining companies the power over this resource. 356
In contrast to the lack of advancement in mining law, in April of 2007, the U.S.
Supreme Court ruled that carbon dioxide indeed was a pollutant under the Clean Air Act.
The Environmental Protection Agency (EPA) followed in April of 2009 with a
declaration that carbon dioxide and other greenhouse gases did pose risks to human and
environmental health. 357 The federal government had begun to take the steps needed to
regulate the emissions from electrical plants powered by fossil fuels. A natural resource
once taken for granted as a ubiquitous part of the earth’s atmosphere increasingly is
coming under government (and not industry) control.

354

Felicity Barringer, “Uranium Exploration Near Grand Canyon,” The New York Times, Feb. 7,
2008, p. A 22.
355

“Uranium Fever Fuels New Land Rush: Mining Claims on U.S. Public Lands Up 47 %,”
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356

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2008, http://www.ewg.org/node/27293, (accessed February 1, 2010).

357

Jonathan Weisman and Siobhan Hughes, “U.S. in Historic Shift on CO2,” The Wall Street
Journal, April 18, 2009, p. A1; “EPA Deems CO2 a Health Risk,” Discovery News,
http://dsc.discovery.com/news/2009/04/17/co2-health-epa.html, (accessed November 3, 2009).

143

In yet another avenue of control, nuclear investment companies or utilities can
regulate the flow of electricity from various electricity sources to their customers. For
example, when summertime demand strains the electrical supply system in California,
local utilities may ask customers to stop using electricity during certain times of the day
as part of a system of “rolling brownouts.” Rather than risking failure of the entire
system, customers must forego satisfying their needs and wants the appliances and
equipment that depend on electricity, for a brief period.
Electric customers are enjoying an increasing amount of power as well.
Customers, particularly residential customers, always have had the freedom to reduce
their electric consumption, and thus their dependence on utilities. Many produce some of
their own electricity by installing solar panels, wind turbines, or small hydroelectric
equipment, feeding excess electricity generated into the local electric grid, and receiving
a credit on their utility bills (a program called “net metering”). 358 Some states now are
considering the European model of requiring utilities to pay customers for the electricity
they generate. 359 (In Germany, residential customers supplying electricity back to the
grid receive a guaranteed payment approximately four times the market rate for
electricity whereas small customers in Spain who provide electricity to the grid receive

358

Database of State Incentives for Renewables and Efficiency,
http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=WA01R&re=1&ee=1,
(accessed November 3, 2009); Laurel Vernado and Michael Sheehan, “Connecting to the Grid:
A Guide to Distributed Generation Interconnection Issues, 6th Edition, 2009,” North Carolina
Solar Center, Raleigh, NC: North Carolina State University, 2009.
359

Kate Galbraith, “Europe’s Way of Encouraging Solar Power Arrives in the U.S.” The
New York Times, March 13, 2009, p. B1.

144

$0.43/kWh. 360 ) Gainesville, FL was one of the first locations in the U.S. to guarantee its
customers payment for their electricity. In February of 2009, the Florida Public Service
Commission approved a $0.34/kWh for 20 years for anyone signing up during the first
two years of the program. 361 This type of program gives the customers control over the
source of their energy and a ‘voice’ in the future of the local utilities: If enough
customers feed into the grid to offset some of the increases in expected demand, the
utility may be able to delay investment in new generation facilities of its own. (In an
interesting twist, however, the feed-in tariffs could be considered a control mechanism
used by the utility companies to entice customers to provide them with the very thing
they sell—electricity.)
The proposed smart grid technology also will give both the utilities and their
customers’ power: The power of having information about exact electrical usage, in real
time, and the cost of the electricity at the time of use. 362 Customers then can schedule
their energy intensive activities when the costs are low and can reduce their total energy
consumption. Utility providers will have details about the precise needs of their
residential and industrial customers, and will be better able to forecast their future needs
360

Ashley Seager, “Germany Sets Shining Example in Providing a Harvest for the World,” The
Guardian, July 23, 2007,
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2009); “New Spanish Feed-In Tariff Level Set,” Renewable Energy World.Com, February 25,
2009, http://www.renewableenergyworld.com/rea/news/article/2009/02/new-spanish-feed-intariff-level-set, (accessed November 3, 2009).
361

“Gainesville Solar Feed-In Tariff a Done Deal,” Renewable Energy World.Com, February 9,
2009, http://www.renewableenergyworld.com/rea/news/article/2009/02/gainesville-solar-feed-intariff-a-done-deal, (accessed November 3, 2009).
362

Brendan Koerner, “Fix the Grid! 7 Ways to Transform America,” Wired, April 2009, pp. 76 –
87; “A Smarter Electric Grid,” February 9, 2009,
http://www.popsci.com/environment/article/2009-02/smarter-electric-grid, (accessed September
24, 2009).

145

and thus determine if construction of new baseload generation capacity is in their best
interest. But, as with new nuclear construction, it will take a financial stimulus from the
federal government to spur the change to the “smarter,” more reliable and efficient
electric grid system. In 2009, the Obama Administration announced $3.4 billion in grant
awards to revamp the electric grid and make electricity distribution and transmission
more efficient. 363
Ultimately, the decision regarding investment in energy technology, whether
nuclear, wind, or even upgrades in transmission, boils down to interplay of the same
factors as outlined in the modified Political Ecology model. It takes an environmental
factor (such as carbon dioxide levels in the atmosphere or a backlash over mining and
extraction practices that reduces the availability of coal, oil, or uranium) plus the demand
for continuously available electricity to power the 24-hour a day, seven days a week
American lifestyle and industrial complex, and financial support for companies in the
United States to tackle energy projects. Thus, the model proposed for new nuclear
reactor construction can be generalized into a model for the Political Ecology of Energy
in the United States:
Natural Resources and

Technology

The Environment

Human Wants
and Needs

Capital Investment/Financing
Figure 13: The Political Ecology of Energy in the United States

363

“President Obama Announces $3.4 Billion Investment to Spur Transition to Smart Energy
Grid,” U.S. Department of Energy Media Release, October 27, 2009,
http://www.energy.gov/news2009/print2009/8216.htm, (accessed November 2, 2009).

146

The next step in this line of research will be to test this model in other sectors of
the electric energy industry in the United States. Do the same relationships hold for
investments in “clean coal” technology, tar sands recovery projects, small-scale
hydropower, concentrating solar installations, or wind farms? Is public demand for
renewable energy sources enough to spur energy firms to put money into new
technologies? Or will representatives of renewable energy companies reveal that
although they firmly believe Americans must move away from a dependence on oil, a
switch to new sources of electricity will occur only with government financial support?
Finding the answers to questions like these could have important implications for policy
and funding decisions at the national and local levels, decisions that will affect the future
direction of energy investments in the U.S. Understanding what drives the renewed
interest in new nuclear power plant construction can help in the development of a wide
variety of programs supporting new technologies designed meet the growing demand for
electricity.
Albert Einstein once said, “The release of atomic energy has not created a new
problem. It has merely made more urgent the necessity of solving an existing one.” 364
Likewise, the impending construction of new nuclear power plants in the U.S. should
stimulate interest in finding other ways to meet the country’s energy needs.

364

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2010.

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171

Appendix 1: Reactor Ownership
Reactor Name

Original Owner

Current Owner

Arkansas Nuclear-1
Arkansas Nuclear-2

Entergy Nuclear
Entergy Nuclear

Beaver Valley-2
Braidwood-1
Braidwood-2
Browns Ferry-1
Browns Ferry-2
Browns Ferry-3

Middle South Utilities via Arkansas Power and Light Co.
Middle South Utilities via Arkansas Power and Light Co.
Duquesne Light Company; Ohio Edison Company; Pennsylvania Power
Company; The Cleveland Electric Illuminating Company; and The Toledo
Edison Company
Duquesne Light Company; Ohio Edison Company; Pennsylvania Power
Company; The Cleveland Electric Illuminating Company; and The Toledo
Edison Company
Commonwealth Edison
Commonwealth Edison
TVA
TVA
TVA

Brunswick-1

Carolina Power & Light Company

Brunswick-2
Byron-1
Byron-2
Callaway-1
Calvert Cliffs-1
Calvert Cliffs-2

Carolina Power & Light Company

Beaver Valley-1

Pennsylvania Power Company (65 percent), Ohio Edison Company (35
percent)
Pennsylvania Power Company (65 percent), Ohio Edison Company (35
percent)
Exelon Corp.
Exelon Corp.
TVA
TVA
TVA
Progress Energy Carolinas (81.7 percent), North Carolina Eastern
Municipal Power Agency (18.3 percent)
Progress Energy Carolinas (81.7 percent), North Carolina Eastern
Municipal Power Agency (18.3 percent)

Columbia-2
Comanche Peak-1
Comanche Peak-2
Cooper

Exelon Corp.
Commonwealth Edison
Exelon Corp.
Commonwealth Edison
Ameren (formerly Union Electric)
Union Electric
Constellation Nuclear
Baltimore Gas and Electric
Constellation Nuclear
Baltimore Gas and Electric
North Carolina Electric Membership Corporation (56.3 percent), Duke
North Carolina Municipal Power Agency Number One, North Carolina
Energy Corporation (25 percent), Saluda River Electric Coop, Inc. (18.8
Electric Membership Corporation, Piedmont Municipal Power Agency,
percent).
and Duke Energy.Operated by Duke Energy
North Carolina Electric Membership Corporation (56.3 percent), Duke
North Carolina Municipal Power Agency Number One, North Carolina
Energy Corporation (25 percent), Saluda River Electric Coop, Inc. (18.8
Electric Membership Corporation, Piedmont Municipal Power Agency,
percent).
and Duke Energy.
Exelon Corp.
Illinois Power
Energy Northwest, Formerly Washington Public Power Supply System or
WPPSS
Energy Northwest
Luminant Generation
TXU Power
Luminant Generation
TXU Power
Nebraska Public Power District
Nebraska Public Power District

Crystal River-3
Davis Besse-1

Florida Progress Corp; operated thru its subsidiary Florida Power Corp.
Cleveland Electric Illuminating (CEI) and Toledo Edison (TE).

Diablo Canyon-1

Pacific Gas and Electric

Diablo Canyon-2
Donald Cook-1
Donald Cook-2
Dresden-2
Dresden-3

Pacific Gas and Electric
Indiana Michigan Power Company
Indiana Michigan Power Company
Commonwealth Edison
Commonwealth Edison

Catawba-1

Catawba-2
Clinton-1

Grand Gulf-1
H.B. Robinson-2

Iowa Electric (later Alliant), Central Iowa Power Cooperative and Corn
Belt Power Cooperative
Detroit Edison
Alabama Power Co.
Alabama Power Co.
Niagara Mohawk Power Corporation
Omaha Public Power District
Early 1970s, Middle South Energy and Mississippi Power & Light coapplicants. In 1980, South Mississippi Electric Power Association
purchased 10 percent of the station
Duke Energy, Progress Energy, SCANA

Hatch-1

Georgia Power, Oglethorpe Power Corp., Municipal Electric Authority of
GA, Dalton Water and Light Sinking Fund Commission

Hatch-2
Hope Creek-1
Indian Point-2
Indian Point-3
Kewaunee
LaSalle-1
LaSalle-2
Limerick-1

Georgia Power, Oglethorpe Power Corp., Municipal Electric Authority of
GA, Dalton Water and Light Sinking Fund Commission
Public Service Electric and Gas
Consolidated Edison
New York Power Authority
Wisconsin Public Service
Commonwealth Edison
Commonwealth Edison
Philadelphia Electric Co.

Duane Arnold-1
Enrico Fermi-2
Farley-1
Farley-2
Fitzpatrick
Fort Calhoun-1

Progress Energy
Cleveland Electric Illuminating
Edison International (75 percent), and San Diego Gas & Electric Co.,
Anaheim Public Utilities Department, and the Riverside Utilities
Department
Edison International (75 percent), and San Diego Gas & Electric Co.,
Anaheim Public Utilities Department, and the Riverside Utilities
Department
American Electric Power Co.
American Electric Power Co.
Exelon Corp.
Exelon Corp.
Florida Power & Light (70 percent), Central Iowa Power Cooperative (20
percent) and the Corn Belt Power Cooperative (10 percent).
Detroit Edison
Alabama Power Co.
Alabama Power Co.
Entergy Nuclear
Omaha Public Power District

Entergy Nuclear
Progress Energy Carolina
City of Dalton, 2.2 percent, Georgia Power Company, 50.1 percent,
Municipal Electric Authority, 17.7 percent, and the Oglethorpe Power
Corp., 30 percent
City of Dalton, 2.2 percent, Georgia Power Company, 50.1 percent,
Municipal Electric Authority, 17.7 percent, and the Oglethorpe Power
Corp., 30 percent
Public Service Electric and Gas
Entergy Nuclear
Entergy Nuclear
Dominion Nuclear
Exelon Corp.
Exelon Corp.
Exelon Corp.

172

Limerick-2
McGuire-1
McGuire-2
Millstone-2
Millstone-3
Monticelllo
Nine Mile Point-1
Nine Mile Point-2

Philadelphia Electric Co.
Duke Energy
Duke Energy
Northeast Utilities
Northeast Utilities
Northern States Power Co.
Mohawk Power Corp.
Mohawk Power Corp.

North Anna-1

Virginia Electric and Power Co.

North Anna-2
Oconee-1
Oconee-2
Oconee-3

Virginia Electric and Power Co.
Duke Energy
Duke Energy
Duke Energy

Oyster Creek
Palisades

GPU Energy via its subsidiary New Jersey Central Power and Light Co.
Consumers Energy Co.
Arizona Public Service, Salt River Project, El Paso Electric Co., So. Cal.
Edison, PNM Resources, So. Cal. Public Power Authority, LA Dept of
Water and Power
Arizona Public Service, Salt River Project, El Paso Electric Co., So. Cal.
Edison, PNM Resources, So. Cal. Public Power Authority, LA Dept of
Water and Power
Arizona Public Service, Salt River Project, El Paso Electric Co., So. Cal.
Edison, PNM Resources, So. Cal. Public Power Authority, LA Dept of
Water and Power
Philadelphia Electric Co.
Philadelphia Electric Co.
Cleveland Electric Illuminating Company (44.9 percent), Ohio Edison
Company (30 percent), Toledo Edison Company (19.9 percent), and
Pennsylvania Power Company (5.2 percent)
Boston Edison
Wisconsin Electric Power Co.
Wisconsin Electric Power Co.
Northern States Power Co.
Northern States Power Co.
Commonwealth Edison
Commonwealth Edison
Rochester Gas and Electric
Cajun Elecric Power cooperative, Gulf States Utilities
Public Service Gas and Electric Company
Public Service Gas and Electric Company

Palo Verde-1

Palo Verde-2

Palo Verde-3
Peach Bottom-2
Peach Bottom-3

Perry-1
Pilgrim-1
Point Beach-1
Point Beach-2
Prairie Island-1
Prairie Island-2
Quad Cities-1
Quad Cities-2
R.E. Ginna
River Bend-1
Salem-1
Salem-2

San Onofre-2

San Onofre-3

Seabrook-1
Sequoyah-1
Sequoyah-2
Shearon Harris-1
South Texas-1
South Texas-2
St. Lucie-1
St. Lucie-2
Surry-1
Surry-2
Susquehanna-1
Susquehanna-2
Three Mile Island-1
Turkey Point-3
Turkey Point-4
Vermont Yankee

Exelon Corp.
Duke Energy
Duke Energy
Dominion Nuclear
Dominion Nuclear
Xcel Energy
Constellation Nuclear
Constellation Nuclear
Dominion Virginia Power corporation (88.4 percent) and by the Old
Dominion Electric Cooperative (11.6 percent).
Dominion Virginia Power corporation (88.4 percent) and by the Old
Dominion Electric Cooperative (11.6 percent).
Duke Energy
Duke Energy
Duke Energy

Exelon Corp.
Entergy Nuclear
Arizona Public Service, Salt River Project, El Paso Electric Co., So. Cal.
Edison, PNM Resources, So. Cal. Public Power Authority, LA Dept of
Water and Power
Arizona Public Service, Salt River Project, El Paso Electric Co., So. Cal.
Edison, PNM Resources, So. Cal. Public Power Authority, LA Dept of
Water and Power
Arizona Public Service, Salt River Project, El Paso Electric Co., So. Cal.
Edison, PNM Resources, So. Cal. Public Power Authority, LA Dept of
Water and Power
Exelon (50 %), PSEG Power (50%)
Exelon (50 %), PSEG Power (50%)
Cleveland Electric Illuminating Company (44.9 percent), Ohio Edison
Company (30 percent), Toledo Edison Company (19.9 percent), and
Pennsylvania Power Company (5.2 percent)
Entergy Nuclear
Florida Power and Light
Florida Power and Light
Xcel Energy
Xcel Energy
Exelon Corp.
Exelon Corp.
Constellation Nuclear
Entergy Gulf States
PSEG Power (57.4 percent), Exelon Corp. (42.6 percent)
PSEG Power (57.4 percent), Exelon Corp. (42.6 percent)
Edison International (75.1 percent), San Diego Gas & Electric Company
Southern California Edison (SCE) (78.21%), San Diego Gas & Electric (20 percent), Anaheim Public Utilities Department (3.2 percent), and the
(20%), and the city of Riverside (1.79%).
Riverside Utilities Department (1.8 percent).
Edison International (75.1 percent), San Diego Gas & Electric Company
Southern California Edison (SCE) (78.21%), San Diego Gas & Electric (20 percent), Anaheim Public Utilities Department (3.2 percent), and the
(20%), and the city of Riverside (1.79%).
Riverside Utilities Department (1.8 percent).
Florida Power and Light (88.2 percent), Massachusetts Municipal
Wholesale Electric Company (11.6 percent), Taunton Municipal Lighting
originally owned by more than 10 separate utility companies serving 5
Plant (0.1 percent), and Hudson Light & Power Department (0.1
New England states
percent)
TVA
TVA
TVA
TVA
Progress Energy, Inc. (83.8 percent), North Carolina Eastern Municipal
Carolina Power and Light
Power Agency (16.2 percent)
Houston Lighting & Power Co. (HL&P), the City of Austin, the City of San NRG Energy (44 percent), CPS Energy (40 percent) and Austin Energy
Antonio, and the Central Power and Light Co. (CPL)
(16 percent)
Houston Lighting & Power Co. (HL&P), the City of Austin, the City of San NRG Energy (44 percent), CPS Energy (40 percent) and Austin Energy
Antonio, and the Central Power and Light Co. (CPL)
(16 percent)
Florida Power and Light
Florida Power and Light
Florida Power and Light, Florida Municipal Power Agency, Orlando
Florida Power and Light
Public Utilities Commission
Virginia Power
Dominion Nuclear
Virginia Power
Dominion Nuclear
PPL Corporation (90 percent), Allegheny Electric Coop, Inc.
PPL Corp., Allegheny Electric Co-op
PPL Corporation (90 percent), Allegheny Electric Coop, Inc.
PPL Corp., Allegheny Electric Co-op
General Public Utilities Corp.
Exelon
Florida Power and Light
Florida Power and Light
Florida Power and Light
Florida Power and Light
Central Vermont Public Service Corp. subsidiary Vermont Yankee
Nuclear Power Corp.
Entergy Nuclear

173

Vogtle-2
Waterford-3
Watts Bar-1

South Carolina Electric & Gas Company (66.7 percent) and Santee
Cooper (33.3 percent)
Georgia Power Company (45.7 percent), Oglethorpe Power Corporation
Georgia Power (45.7%), Oglethorpe Power Corporation (30%), Municipal (30 percent), Municipal Electric Authority of Georgia (22.7 percent), and
Electric Authority of Georgia (22.7%) and the City of Dalton (1.6%).
the City of Dalton, Georgia, (1.6 percent).
Georgia Power Company (45.7 percent), Oglethorpe Power Corporation
Georgia Power (45.7%), Oglethorpe Power Corporation (30%), Municipal (30 percent), Municipal Electric Authority of Georgia (22.7 percent), and
Electric Authority of Georgia (22.7%) and the City of Dalton (1.6%).
the City of Dalton, Georgia, (1.6 percent).
Louisiana Power and Light
Entergy Louisiana
TVA
TVA

Wolf Creek

Kansas City Power and Light (KCPE) and the Wichita-based Kansas
Gas and Electric (KG&E).

Virgil C. Summer- 1

Vogtle-1

South Carolina Electric & Gas Company, South Carolina Public Service
Authority

Wolf Creek Nuclear Operating Corporation (WNOC): WCNOC is a jointlyowned corporation formed by the owners: Westar, a Western Resources
company, Kansas City Power & Light Company (KCPL) and Kansas
Electric Power Cooperative, Inc. (KEPCo).

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http://en.wikipedia.org/wiki/Three_Mile_Island_Nuclear_Generating_Station, (accessed October
7, 2008);
“Union Electric selects Alpharel for Callaway Nuclear,” March 23, 1995,
http://findarticles.com/p/articles/mi_m0EIN/is_1995_March_23/ai_16705292, (accessed October
7. 2008);
“Vermont Yankee Nuclear Power Corporation,”
http://investing.businessweek.com/research/stocks/private/snapshot.asp?privcapId=1080422,
(accessed October 7, 2008);
“Vogtle Electric Generating Plant,”
http://en.wikipedia.org/wiki/Vogtle_Electric_Generating_Plant, (accessed October 7, 2008).

177

178

179

Appendix 2: Timeline

181

182

183

184

366

D. Victor Anderson, Illusions of Power: A History of the Washington Public Power Supply System, New York: Praeger, 1985;
Jack Barkenbus, “Nuclear Power Safety and the Role of International Organization,” International Organization, Vol. 41, No. 3 (Summer, 1987),
pp. 475 – 490.
Steven L. Del Sesto, Science, Politics, and Controversy: Civilian Nuclear Power in the United States, 1946 – 1974, Boulder, CO: Westview
Press, 1979;
Kathryn Kranhold, “Nuclear-Power Industry Sees Signs of a U.S. Revival; Utilities Face Opposition Over Safety and Storage; A GEWestinghouse Contest,” The Wall Street Journal, November 9, 2004, p. A.1;
James Leigland, and Robert Lamb, WPP$$: Who is to Blame for the WPPSS Disaster, Cambridge, MA: Ballinger Publishing Co., 1986;
John Lillington, The Future of Nuclear Power, Maryland Heights, MO: Elsevier, 2004;
Constance Perin, Shouldering Risks: The Culture of Control in the Nuclear Power Industry, Princeton, NJ: Princeton University Press, 2006;
Bobette Riner, “2008 Poised to Become the Year of the Nuke,” Natural Gas Week, January 7, 2008;
John C. Zink, “Past Year's Events Favor Nuclear Resurgence,” Power Engineering, January 2003,
http://pepei.pennnet.com/display_article/166316/6/ARTCL/none/none/1/Nuclear-Reactions:-Past-Year's-Events-Favor-Nuclear-Resurgence/;
“Causes of Cost Overruns and Schedule Delays on the Five WPPSS Nuclear Power Plants,” Report to the Washington Sate Senate and 47th
Legislature of the Washington State Senate Energy and Utilities Committee, WPPSS Inquiry, Vol. 1, January 12, 1981;
“Combined License Applications for New Reactors,” U.S. NRC, http://www.nrc.gov/reactors/new-reactors/col.html;
“DOE Announces Solicitations for $30.5 Billion in Loan Guarantees", June 30, 2008, www.energy.gov/news/6377.htm, (accessed July 7, 2008);
“Entergy Nuclear,” www.entergy-nuclear.com/new_nuclear/nustart.aspx, (accessed May 24, 2008);
“INPO, Institute of Nuclear Power Operations, About Us,” http://www.inpo.info/AboutUs.htm, (accessed May 21, 2008);

185

"Institute of Nuclear Power Operations Institutional Plan, 1993", www.osti.gov/bridge/servlets/purl/10116681179FnT/webviewable/10116681.pdf, (accessed May 21, 2008);
“Institute of Nuclear Power Operations (INPO) Liaison,” DOE Office of Health, Safety and Security, http://www.hss.energy.gov/CSA/CSP/inpo/,
(accessed May 21, 2008);
“National Energy Policy Report of the National Energy Policy Development Group: Reliable, Affordable, and Environmentally Sound Energy for
America’s Future,” Washington D.C.: U.S. Government Printing Office, May 2001;
“Nuclear Plant Personnel Training Facts,” www.nukeworker.com/study/radiation_faqs/Training_Facts.shtml, (accessed May 24, 2008);
“Nuclear Power 2010, Overview,” U.S. Department of Energy,
http://www.ne.doe.gov/np2010/overview.html, (accessed May 2, 2008);
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http://www.eia.doe.gov/cneaf/nuclear/page/at_a_glance/reactors/nuke1.html;
“NuStart Energy,” http://www.nustartenergy.com/, (accessed May 24, 2008);
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“Our History,” U.S. NRC, http://www.nrc.gov/about-nrc/history.html, (accessed July 2, 2008).

186

Appendix 3: Construction Extremes
Of the five reactors with the most extreme times between construction start and
coming on line, three are pressurized water reactors (PWRs) and two are boiling water
reactors (BWRs), suggesting that factors other than reactor type drove the construction
delays. Those factors are described in this Appendix.

1.0 Westinghouse Nuclear Reactor Systems
1.1 Comanche Peak (PWR near Glen Rose, TX)
Architect/Engineer: Gibbs and Hill
Two 1150 MW Pressurized Water Reactors
The Comanche Peak nuclear power project, Texas Utility Company’s first foray
into nuclear, got off to a rocky start. The original design firm was fired before the power
plant plans were completed. 367 Even after the blueprints were finished, design of reactor
components continued to change, with over 500 change documents generated for cable
tray supports alone! 368 Construction of Comanche Peak nuclear power plant did begin in
October of 1974 with operations scheduled to begin in 1980. 369 However, in 1979
allegations arose of poor quality construction practices, opening the doors to
investigations by the Nuclear Regulatory Commission (NRC) that uncovered a myriad of
problems at the site. Areas of concern included:

367

Randy Lee, “Comanche Peak Given Full License—Unanimous Vote Ends 10-Year Delay,”
The Dallas Morning News, April 17, 1990, p. 1a.

368

Jim Landers, “Consultants Find 80 Questionable Comanche Peak Design Points,” The Dallas
Morning News, April 27, 1985, p. 42a.

369

Lee; Mark Edgar, “Comanche Peak Start-up Delayed,” The Dallas Morning News, April 19,
1986, p. 1a.

187













370

Hiring of companies that had no prior experience building nuclear power facilities
and thus were unfamiliar with NRC construction standards. 370
Failure to document apparent design deficiencies in components of the reactor
system, such as the electric cable trays and pipe supports. 371
Failure to keep adequate records of analyses of system structures. 372
Problematic welds. 373
Faulty earthquake design features. 374 For example, a ceiling in the control room
had to be replaced when it was determined it could collapse onto operators during
an earthquake. 375
Inadequate documentation of the strength of the concrete used and claims that
available reports had been falsified. 376
Omission of reinforcing bars in a portion of the concrete wall surrounding the
reactor cavity. 377
Misinterpretation of testing procedures, alteration of those procedures via memo
or in conversation, and failure to have test results independently verified. 378
Failure to document important safety violations and conduct follow-up reviews. 379
Reports of harassment of quality control inspectors and inappropriate handling of
whistle-blowers (which led to lawsuits and $5.5 million in payments). 380
Insufficient training of plant personnel. Only 45% of candidates for nonsupervisory positions passed their Nuclear Regulatory exams in 1983 despite six
years of training. In 1985, 47% passed after 18 months of revised training. 381

Hossein Hamzehee, Nuclear Regulatory Commission, Telephone Interview of May 14, 2009.

371

Edgar; Landers; Real, David, “More Study of N-Plant Ordered. . .NRC Official Expects Delay
in Fuel Loading,” The Dallas Morning News, October 2, 1984, p. 1a.

372

Hamzehee.

373

Lee.

374

David Real, “Hearings Crucial to N-Plant, At Stake: Licenses for Comanche Peak,” The
Dallas Morning News, September 23, 1984, p. 37a.

375

David Real, “Nuclear Plant Reschedules Fuel Loading—Comanche Peak Delay Could Cost
Millions,” The Dallas Morning News, October 10, 1984, p. 23a.

376

Real, September 23, 1984.

377

Real, October 10, 1984.

378

Real, October 2, 1984.

379

Ibid.

380

Real, September 23, 1984; David Real, “N-Plant Fueling Delay Requested—Group Cites
Court Appeal,” The Dallas Morning News, October 17, 1989, p. 25a.

188

In addition, Texas Utilities Generating Company had to renew a construction
permit that expired in 1985, and had to contend with a battery of lawsuits initiated by the
Citizens for Sound Energy, an anti-nuclear group.
In November of 1985, Texas Utilities turned to the U.S. Navy to help transform
operations at Comanche Peak. Rear Admiral Austin B. Scott Jr., former submarine
commander and pupil of “nuclear Navy” founder Admiral Hyman Rickover, was hired to
instill discipline and uncompromising standards of excellence. 382 Resolving all of the
problems added a decade to the construction schedule and billions to the cost of
Comanche Peak. But Texas Utilities was financially strong and determined to see the
project through to completion. 383 The first unit finally received its operating license on
April 16, 1990 and started commercial operations on August 13, almost 16 years after
construction started. Originally slated to cost $779 million, the final figure for the plant
reached over $9.1 billion. 384
1.2 Diablo Canyon (PWR outside of San Luis Obispo, CA)
Architect/Engineer: Pacific Gas and Electric
Two Pressurized Water Reactors,1122 MW and 1118 MW
The NRC issued the construction permit for unit 1 of Diablo Canyon in April of
1967. The second unit received its construction permit in 1970. Although there had been

381

David Real, “N-Plant Utility Hopes for Better Test Scores—45% Failed Last Reactor Operator
Exam,” The Dallas Morning News, May 12, 1985, p. 33A.

382

David Real, “Rear Admiral to Head N-Plant,” The Dallas Morning News, October 22, 1985, p.
17a.

383

Hamzehee.

384

Real, David, “Comanche Peak Cost Rises Again—Texas Utilities Announce $2 billion
Overrun, Delay Until ’89,” The Dallas Morning News, November 26, 1986, p. 1a; Lee.

189

some questions about the adequacy of the designs to resist earthquakes, outside
consultants concluded that earthquake epicenters in the vicinity did not threaten the safety
of the nuclear power plant. 385 Then, in 1971, Shell Oil Co. geologists Hoskins and
Griffiths published a paper describing the previously unknown Hosgri Fault three miles
off the coast. But it was not until after Pacific Gas and Electric submitted its operating
license applications in 1973 that the NRC began an evaluation of that fault and its
implications for Diablo Canyon. According to Edison Case, Acting Director of the
Office of Nuclear Reactor Regulation of the NRC, in his testimony before the Committee
on Interior and Insular Affairs of the House of Representatives, 6/30/77,
In conjunction with the limited resources available to assist the NRC
was the fact that the number of applications under review by us and our
consultants was significant and increasing. . . The situation was such
that, once a construction permit was issued, the specialists within the
staff and its consultants having detailed knowledge of a given safety
matter for a specific facility would not likely have the time to survey
the literature in order to determine the significance of that information
to that facility. Those individuals were involved with other problems
on other applications. 386
Despite the added earthquake concerns, work continued on the Diablo Canyon
units. 387 As a result, the newly built structures and equipment had to be modified to meet
the more stringent seismic standards.
Astonishing quality assurance issues came to light in 1981 when the NRC issued
a low-power operating license for unit 1. 388 Drawings for unit 1 had been interchanged

385

“Oversight on Diablo Canyon Nuclear Generating Plant, Oversight Hearing Before the
Subcommittee on Energy and the Environment of the Committee on Interior and Insular Affairs,
House of Representatives, June 30, 1977,” Washington D.C.: U.S. Government Printing Office,
1977, p. 3.

386

Ibid, p. 5.

387

Ibid, p. 28.

190

with drawings for unit 2 so that each unit was analyzed using data gathered for the other
unit. That finding led to further discoveries of the structures not conforming to NRC
requirements and extensive remedial work on the two units: There were over 300
discrepancies between the NRC safety standards, the design of Diablo Canyon, and the
constructed units. 389 Experience of the operators and the adequacy of the emergency
preparedness plan also came into question. 390
Public opinion regarding nuclear power and the NRC eroded in light of the
problems that surfaced at Diablo Canyon. The Oversight Hearing of 1984, held in San
Luis Obispo, CA, included testimony from a panel of local mayors, members of the San
Luis Obispo Mothers for Peace, the Citizens for Adequate Energy, representatives of the
Abalone Alliance and the Citizens for Effective Emergency Planning, and over 65 local
residents. Another 34 submitted statements to the Committee. Amy Shore expressed
concern about the impact of Diablo Canyon on the ocean: “I do not trust the NRC, and I
do not trust PG & E. These agencies are concerned only with PG & E’s investment and
are a detriment to the survival of our ecosystem.” 391 Catherine Jacobs spoke about
nuclear waste: “[H]ow are we going to transport this waste from our county once it is
produced if they put the plant on line? The railroad tracks here are getting in bad
388

389

Ibid, p. 6.

390

391

Ibid, p.104.

191

condition, and are getting worse. . .If that causes a train to derail with nuclear waste on
board, we could have leakage. And there is no way to get out in time.” 392 According to
Kevin O’Shea: “Our time is short on this Earth and we have no right to poison it for
future generations.” 393 Most people who testified favored shutting down Diablo Canyon
for health and safety reasons. Despite such public concerns, the NRC granted full-power
operating licenses. Unit 1 went on-line November 2, 1984. Unit 2 followed on August
26, 1985.
1.3 Watts Bar (PWR, Spring City, TN)
Architect/Engineer: Tennessee Valley Authority
1121 MW Pressurized Water Reactor
In the 1960s, buoyed by forecasts of steadily increasing demand for electricity
and concerned about the potential for depletion of fossil fuels in the United States in
general and the Tennessee valley in particular, the Tennessee Valley Authority (TVA)
undertook the construction of 17 nuclear power plants over a period of ten years. 394
“[W]e know how to build dams, we know how to build coal plants, so we must know
how to build nuclear plants.” 395 Construction of the Browns Ferry nuclear plant begin in
1966, Sequoyah in 1969, and Watts Bar in 1972. Unfortunately, the TVA had neither the
expertise in nuclear power nor the personnel qualified to oversee all of those projects. 396
As Marvin Runyon, then Chairman of the TVA Board of Directors, testified before a
392

Ibid, p. 103.

393

Ibid, p. 115.

394

“TVA’s Nuclear Program: Hearing Before the Subcommittee on Investigations and Oversight
of the Committee on Public Works and Transportation, House of Representatives, March 22,
1988,” Washington D.C.: U.S. Government Printing House, 1988, pp. 1 and 9.
395

Ibid, p. 10.

396

Ibid, p. 1.

192

Congressional subcommittee in 1988, “TVA started more and more nuclear plants and all
of a sudden it was building so many of them that it didn’t have the people to do the
job.” 397
By 1980, only five units of the originally planned units were operational. 398 Then
in 1985, the TVA shut down all of their nuclear power facilities, including both those in
operation and those still under construction, to step back and re-evaluate its nuclear
ambitions.
What were the TVA’s major problems? To begin with, demand forecasts
underlying the construction program relied on a straight-line extrapolation of historical
growth. 399 Like others in the industry, they had not accounted for slowdowns in the
economy, changes in technology that made common household machines more energy
efficient, or the fuel crisis of the 1970s that spurred conservation programs. 400 The
planned nuclear power plants would generate much, much more electricity than the area
needed. Revised forecasts of the 1980s looked at different scenarios for growth,
describing a range of possible futures, and set boundaries within which the TVA could
invest. Those forecasts supported restart of the five units at Sequoyah and Browns Ferry.
Bellefonte and Watts Bar 1 were expected to be brought on in the mid early to mid1990s.

397

Ibid, p. 10.

398

Ibid.

399

Ibid, p. 16.

400

Ibid, p. 10.

193

Quality assurance during construction also was a concern, particularly at Watts
Bar, where the integrity of welds became an issue. 401 After the Three Mile Island
accident, when the NRC tightened its safety regulations, the TVA did not have the people
or the procedures in place to ensure that those regulations were being implemented. 402
Those lapses ultimately led to the shutdown in 1985.
After the shutdown in 1985, TVA brought in Admiral Steven White as Manager
of the Office of Nuclear Power. Under his guidance, the TVA implemented programs to
identify and correct construction deficiencies. He instituted comprehensive training for
TVA managers and team building exercises. He tried to reduce the reliance on contract
personnel, a practice that had taken its toll on the experienced staff the TVA did hire. 403
In the mid-1990s, the TVA decided not to complete the Bellefonte nuclear units
or Watts Bar 2, in an effort to control finances (“TVA 1999 Annual Report, Notes to
Financial Statements: Nuclear Power Program,” “Energy Vision 2020, Executive
Summary, Integrated Resource Plan, Environmental Impact Statement”). 404 However, in
2005, the TVA applied for a license to install new AP1000 reactors at the Bellefonte site,

401

Ibid, p. 50.

402

Ibid, p. 14.

403

Ibid, p. 45.

404

“TVA 1999 Annual Report, Notes to Financial Statements: Nuclear Power Program,”
http://www.tva.gov/finance/reports/annualreport_99/ar_nuc1.htm, (accessed October 9, 2008);
“Energy Vision 2020, Executive Summary, Integrated Resource Plan, Environmental Impact
Statement,” http://www.tva.gov/environment/reports/wattsbar2/related/2020_exec_summary.pdf,
(accessed October 9, 2008).

194

and in 2007 elected to complete construction of Watts Bar 2 to help meet a renewed
growth in demand for electricity (“TVA’s Nuclear at a Glance”). 405
2.0 General Electric Nuclear Reactor Systems
2.1 Fermi 2 (BWR, northeast of Toledo, OH)
Architect/Engineer: Sargent and Lundy
1122 MW Boiling Water Reactor
Detroit Edison embarked on an ambitious venture to build the largest nuclear
power plant in the country (1100 MW(e)) when it broke ground for Fermi 2 in 1969. 406
Construction was expected to take six or seven years. 407 The first signs of trouble
appeared in 1974 when that construction stopped for over two years due to cash shortages
at Detroit Edison and the utility sought out other partners for the project to help pay for
the plant. 408 Construction did not resume until 1977.
Tightened safety regulations implemented by the NRC in the wake of the 1979
Three Mile Island accident led to costly delays for repair, redesign, and retooling to meet
the new requirements. 409 Then in 1985, an operator accidentally and unknowingly
triggered a nuclear chain reaction, raising new concerns about safety at the plant. That
same year, Detroit Edison began a program of evaluation of the plant equipment and
405

“TVA’s Nuclear at a Glance,” http://www.tva.gov/power/nuclear/nuclear_fact_sheet.pdf,
(accessed October 9, 2008).
406

Christopher Cook, “Fermi Gets Ok to Use Full Power,” Detroit Free Press, January 16, 1988;
John Lear, “How Fermi 2 Stacks Up: Edison Execs Look for a Rosy Future, but Regulators are
not yet Convinced,” Detroit Free Press, January 16, 1989.
407

George White, “Fermi 2 Starts up Commercially, Rate Increase to Pay for Plant Takes Effect
Today,” Detroit Free Press, January 24, 1988.

408

“Off by $4 Billion and 14 Years, Michigan Nuclear Plant Starts,” The New York Times,
January 24, 1988 p. 1.28.
409

White.

195

operators, in prelude to commencing full power operations. So many problems arose
during the evaluation that the NRC restricted the utility’s operations at Fermi 2 and levied
fines amounting to $600,000 for violations of federal safety regulations and “miscues”
during the testing program. 410 The plant also faced fines of up to $100,000 for 26
operating violations found in 1985. 411 In the end, tests that usually take about six months
to complete took 2 ½ years at Fermi 2.
Like Diablo Canyon, the Fermi 2 project faced opposition from area
environmental groups, such as the Safe Energy Coalition, which distributed balloons
bearing the message “The winds which brought you this balloon could also bring you
radioactive material from Fermi 2.” 412 The Servants of the Immaculate Heart of Mary, a
convent of Roman Catholic nuns who resided in the nearby town and feared the potential
hazards of having a nuclear reactor in their backyard and worried about the problems of
dealing with nuclear wastes, raised the issues during shareholder meetings. 413 And
lawsuits filed by the consumer group, the Michigan Citizens Lobby, delayed the project
as courts heard arguments over proposed customer rate increases and the issuance of
securities to pay for the construction. 414

410

Ibid.

411

“Around the Nation; Michigan Nuclear Plant is Cited in 26 Violations,” The New York Times,
January 12, 1986.
412

David Shepardson, “Edison to Close Nuke Plant,” The Detroit News, April 12, 1998,
http://www-personal.umich.edu/~sanders/214/other/news/fermi2.html, (accessed February 1,
2010).
413

“Vote Backs Plant for Detroit Edison,” The New York Times, April 24, 1984; Deborah Kaplan,
“Foes Lament Ok for Full Power at Fermi 2; 20 March in Rain, Vow to Continue Nuclear War,”
Detroit Free Press, January 18, 1988.

414

“Michigan Utilities,” The New York Times, January 28, 1982, p. D.14;

196

Despite the years of setbacks, Detroit Edison received the green light from the
NRC to run Fermi 2 at full power in January of 1988. When Fermi 2 finally did begin
commercial operations, it was 14 years late and $4.1 billion over budget. 415
2.2 Limerick 2 (BWR near Philadelphia, PA)
Architect/Engineer: Bechtel
1134 MW Boiling Water Reactor
Budget woes and community interests, not construction issues, delayed
Philadelphia Electric’s Limerick 2 nuclear power plant. 416 Philadelphia Electric
proposed its Limerick 1 and 2 plants in 1969 to meet anticipated demand growth in the
Philadelphia area. Ground was broken for both facilities in 1974, with the aim of
completing them in tandem. But financial problems forced the utility to slow
construction in the late 1970s. 417 In May of 1982, the Pennsylvania Public Utilities
Commission ordered the company to stop borrowing money to continue building
Limerick 2 until Limerick 1 had been completed. 418 In addition, the Utilities
Commission expressed concern that Limerick was no longer in the public interest, due to
escalating costs and the potential for overcapacity. 419 Construction on Limerick 2 came
to a halt; it was only 30% complete. 420
415

“Off by $4 Billion and 14 Years, Michigan Nuclear Plant Starts,” The New York Times,
January 24, 1988 p. 1.28.
416

Jeff Barker, “PE Granted License for Limerick 2,” The Philadelphia Inquirer, August 26,
1989, p. A01; Dan Stets, “Limerick 2 Too Costly, PUC Consultant Says,” The Philadelphia
Inquirer, September 15, 1989, p. C13.

417

Stets, September 15, 1989.

418

Matthew L. Wald, “Building Reactors the New Way,” The New York Times, July 17, 1989, p.
D.1.

419

Barker.

420

Wald, July 17, 1989.

197

Limerick 1 received its Nuclear Regulatory Commission operating license in
1985.
Work on Limerick 2 resumed in 1986 after a delay of about 3 ½ years.
Philadelphia Electric had agreed to hold costs to $3.2 billion, with any cost overruns to be
borne by the utility stockholders and not its ratepayers. 421 The utility was able to share
some of the schedule risk with its primary contractor, Bechtel, by promising Bechtel a
$60 million bonus for finishing the project early. A special agreement with the labor
unions barred strikes and limited wage increases for Limerick workers. In addition, the
delay allowed Philadelphia Electric to finish the design and engineering for the facility,
reducing the number of design changes that occurred in the field.
However, two other issues delayed completion of Limerick 2: (1) The need to
get Department of Environmental Resources permission to install an industrial chiller and
cooling towers in Bucks County, PA, to equalize the temperature of water from the
Delaware River and Perkiomen Creek into which it would be diverted 422 and (2) A
lawsuit on behalf of the Limerick Ecology Action group to investigate the need for
additional damage control measures at the plant in the event of an accident. 423 As a result
of the latter, Philadelphia Electric did agree to strengthen its ability to solidify molten
material in case of a core meltdown and to provide a back-up system for preventing

421

Ibid.

422

Dan Stets, “For PE, Two Rounds To Go In the Fight for Limerick 2,” The Philadelphia
Inquirer, May 15, 1989, p. C01.

423

Dan Stets, “PE Seeks Green Light on Limerick,” The Philadelphia Inquirer, June 7, 1989, p.
B06.

198

pressure build-up in the containment vessel. 424 The Limerick Ecology Action group also
received unprecedented access to the plant for inspections over the next 4 ½ years.
Despite those setbacks, the Nuclear Regulatory Commission finally did approve a fullpower operating license for Limerick 2 on August 25, 1989, 20 years after
groundbreaking.

424

Barker.

199

200

Appendix 4: Partial Text of H.R. 1029 of 1985 425
A Bill
To amend the Atomic Energy Act of 1954 to encourage the development and use of
standardized plant designs and improve the nuclear licensing and regulatory process.
Short Title
Section 1. This Act may be cited as the “Nuclear Powerplant (sic) Standardization Act of
1985”.
2
Findings and Purposes
Sec. 2. (a) The Congress, recognizing that a clear and coordinated energy policy
consistent with the public health and safety must include an effective and efficient
licensing process for the siting, construction, and operation of nuclear powerplants (sic)
that meet applicable criteria, hereby finds that—
(1) interstate commerce is substantially affected by the siting, construction, and
operation of nuclear powerplants (sic);
(2) opportunity for meaningful public participation in the siting and licensing of
nuclear powerplants (sic) should be assured;
(3) the licensing and construction of nuclear powerplants (sic) will be facilitated
and the public health and safety enhanced by the use of preapproved nuclear
powerplant (sic) designs, particularly standardized designs;
(4) there is a need to encourage the development and use of standardized nuclear
powerplant (sic) designs because (A) such designs can benefit public health
and safety by concentrating the resources of designers, engineers, and vendors
on particular approaches, by stimulating standardized programs of
construction practice and quality assurance, by improving the training of
personnel, and by fostering more effective maintenance and improved
operations; and (B) the use of such designs can permit a more effective and
efficient licensing and inspection process;

425

201

(5) the licensing process will be facilitated by procedures for the selection and
approval of a site for a nuclear powerplant (sic) to be accomplished in
advance of a commitment to construction a particular facility of a specific
design at such site;
(6) the licensing and regulatory process will be facilitated if the licensing decision
are made at the earliest feasible phase of the process and issues resolved in
Nuclear Regulatory Commission proceedings are not subject to further
adjudication in the absence of a substantial evidentiary showing required by
this Act and the regulations of the Nuclear Regulatory Commission;
(7) consistent with the adequate protection of the public health and safety and the
common defense and security, the regulatory process should provide greater
stability in licensing standards and criteria for approved designs of nuclear
powerplants (sic);
...
(b) The purposes of this Act are—
(1) to facilitate the use of preapproved sites and designs for nuclear powerplants
(sic) and to facilitate the development and use of standardized designs;
(2) to provide for the issuance of a license to construct and operate a nuclear
powerplant (sic) under conditions that enhance the protection of the public
health and safety and are in accord with the common defense and security;
and
(3) to improve the stability of licensing standards, criteria for nuclear powerplants
(sic), and prior Nuclear Regulatory Commission licensing approvals.
Approval of Standardized Designs
Sec. 193. Approval of Standardized Designs.—
a. (1) The Commission shall establish procedures, standards, and criteria permitting
the approval of standardized facility designs for any utilization or production
facility for industrial or commercial purposes, or any discrete subsystem thereof,
for a period of ten years, notwithstanding the fact that an application has not been
filed for a construction permit or license to construct and operate for such facility.
For purposes of this Act, a design approval shall be considered to be a license.
(2) A design approval issued by the Commission under this section shall be
conclusive with respect to an application for a construction permit, an operating
license, or a license to construct and operate that meets the conditions of the
approval and is filed within the period during which the approval remains valid.
b. The Commission shall establish procedures for the renewal of design approvals
issued under subsection a. for additional ten year periods from the date of
renewal. Upon application for renewal of a design approval, the Commission
shall renew the approval unless it finds that significant new information relevant
to the design has become available that makes it likely that the design will not

202

Construction and Operating Licenses
Sec. 185. Construction Permits, Operating Licenses, and Construction and Operating
Licenses.—
a. An applicant for a license to construct or modify a utilization or production
facility for industrial or commercial purposes shall, after the Commission has
provided an opportunity for public hearing pursuant to section 189 and if the
application establishes competency and is otherwise acceptable to the
Commission, be initially granted a construction permit. Upon filing of additional
information by the applicant needed to bring the original application up to date,
the Commission shall, after providing an opportunity for public hearing pursuant
section 189, issue an operating license to the applicant upon finding that the
facility authorized has been constructed and will operate in conformity with the
application as amended, the provisions of this Act, and the rules and regulations
of the Commission. For purposes of this Act, a construction permit shall be
considered a license.
b. (1) The Commission may issue a license to an applicant to construct and operate a
utilization or production facility for industrial or commercial purposes after
providing opportunity for public hearing pursuant to section 189, if the
application is sufficient to enable the Commission to determine that the applicant
is competent and that the facility will be constructed and will operate in
conformity with the provisions of this Act, and the rules and regulations of the
Commission. For the purposes of this Act, a license to construct and operate shall
be considered to be a license.

203

204

Appendix 5: Brief Overview of New Reactor Design Features
1.0 Evolutionary Power Reactor from Areva Nuclear Power (EPR) 426
 Builds on experience gained with reactors operating in France and Germany;
 Now being built in Finland, France, and China;
 Includes four emergency core cooling systems instead of the usual two, allowing
one to be shut down for repair or maintenance without compromising reactor
safety;
 Has added a “core spreading area” to trap and cool molten material
in case of a core meltdown;
 “Defense in depth” design;
 Increased efficiency core optimizes fuel use, allows for a longer period between
refueling, and reduces waste production;
 Permits access to the containment while the reactor is operating, reducing the
down time for maintenance and refueling;
 Designed for a 60 year life versus the current 40 year standard;
 Able to use reprocessed uranium fuels;
 Rated at 1600 MW(e);
 Design certification application received by the NRC in December, 2007.
2.0 General Electric/Hitachi Advanced Boiling Water Reactor (ABWR) 427
 Already in use in Japan and under construction in Taiwan;
 Designed for ease of maintenance, saving time and money;
 Relies on fewer pumps than previous G.E. designs;
 Eliminates large pipes below the level of the core to reduce the chance of leakage;
 Allows decay heat (heat given off by radioactive material even after the fission
reaction has stopped) to escape for 72 hours, even without operator intervention;
 Uses pre-assembled, modularized components, decreasing construction time;
 Can be constructed in 39 months;
426

“Design Certification Application Review--U.S. Evolutionary Power Reactor (U.S. EPR),”
http://www.nrc.gov/reactors/new-licensing/design-cert/epr.html, (accessed July 2, 2008); “EPR:
the first generation III+ reactor currently under construction,” http://www.arevanp.com/scripts/info/publigen/content/templates/show.asp?P=715&L=US&SYNC=Y, (accessed
November 3, 2008); Matthew L. Wald, “Power Producers Seek Latest Models of Nuclear
Reactors,” The New York Times, March 15, 2005.
427

“ABWR Overview,” http://www.ne.doe.gov/np2010/pdfs/ABWROverview.pdf, (accessed
November 3, 2008); “Advanced Boiling Water Reactor Fact Sheet,”
http://www.gepower.com/prod_serv/products/nuclear_energy/en/downloads/gea14576e_abwr.pdf
, (accessed November 3, 2008); “G.E. Advanced Boiling Water Reactor,”
http://groups.msn.com/AAEA/geabwr.msnw, (accessed July 2, 2008); Matthew L. Wald, “Power
Producers Seek Latest Models of Nuclear Reactors,” The New York Times, March 15, 2005.

205




Produces 1350 to 1460 MW(e);
Design certification for the 1350 MW model issued in May, 1997.

3.0 General Electric/Hitachi Economic Simplified Boiling Water Reactor
(ESBWR) 428
 Designated as the next generation of boiling water reactor, incorporating proven
features of the ABWR;
 Incorporates passive safety features and a gravity driven cooling system, thus
reducing the number of the pumps, valves, and motors by 25% versus previous
reactor designs;
 Eliminates the need for a backup generator;
 Leads to faster construction, reduced maintenance, lower costs,
and increased reliability and safety;
 Construction time: 42 months;
 Provides about 1600 MW(e);
 Application for design approval submitted in August of 2005.
4.0 Mitsubishi Heavy Industries U.S. Advanced Pressurized Water Reactor
(USAPR) 429









Higher efficiency version of a design scheduled to start construction in 2010 in
Japan;
 Evolved from the pressurized water reactors currently in operation
in the U.S.
Incorporates four reactor coolant loops and four coolant system loops for
enhanced safety;
 Design modifications should result in 90% fewer shutdowns
compared to other four loop pressurized water reactors;
Able to use fuels made from reprocessed nuclear wastes;
Produces 1700 MW(e);
Certification application submitted December of 2007.
Customer: Luminant Generation Company, LLC for Comanche Peak.

428

“Design Certification Application Review--Economic Simplified Boiling-Water Reactor
(ESBWR),” http://www.nrc.gov/reactors/new-reactors/design-cert/esbwr.html, (accessed
November 3, 2008); “ESBWR Fact Sheet,”
http://www.gepower.com/prod_serv/products/nuclear_energy/en/downloads/gea14429g_esbwr.p
df, (accessed November 3, 2008); “ESBWR Overview,”
http://www.ne.doe.gov/np2010/pdfs/esbwrOverview.pdf, (accessed November 3, 2008).
429

“Mitsubishi US--APR Design Overview,” http://www.ne.doe.gov/np2010/pdfs/2%20%20USAPWR%20Overview.pdf, (accessed November 3, 2008); “US—APR Design,” http://www.mnesus.com/htm/usapwrdesign.htm, (accessed November 3, 2008).

206

5.0 Westinghouse AP1000, Advanced Passive Boiling Water Reactor 430








Based on a “tried and true” U.S. reactor design dating back to the 1950s;
Relies on passive, non-mechanical safety features rather than pumps, generators,
and valves, reducing cost and increasing reliability;
 Contains 83% fewer safety related pipes and 1/3 the number of
pumps as its predecessor;
 Houses the water for emergency cooling inside the containment
structure and can provide gravity-driven flow even if all power
fails;
Employs a modular design, allowing portions of the reactor to be fabricated offsite, improving quality control during their manufacture and decreasing the onsite construction time;
 Estimated time to completion: Three years;
Provides approximately 1100 MW(e);
AP600 was certified in 1998; AP1000 was certified in January 2006, but
Westinghouse submitted design modifications in May 2007, forcing a re-review
by the NRC. In October of 2009, the NRC informed Westinghouse of concerns
about the ability of the revised AP1000 shield building (which protects the
reactor’s primary containment) to withstand severe weather and other events.
Design modifications and further testing of the structure may be required.

430

“AP1000,” http://www.ap1000.westinghousenuclear.com, (accessed November 4, 2008); “A
Roadmap to Deploy New Nuclear Power Plants in the United States by 2010, Volume I,
Summary Report,” Prepared by the Near Term Development Group for the United States
Department of Energy, Office of Nuclear Energy, Science and Technology, and the Nuclear
Energy Research Advisory Committee, Subcommittee on Generation IV Technology Planning,
October 31, 2001; Blake, E. Michael, “Renaissance Now?” Nuclear News, January 2008, pp. 24 –
30; “Design Certification Application Review--AP1000 Amendment,”
http://www.nrc.gov/reactors/new-reactors/design-cert/amended-ap1000.html, (accessed
November 3, 2008); Matthew L. Wald, “Power Producers Seek Latest Models of Nuclear
Reactors,” The New York Times, March 15, 2005; “NRC Informs Westinghouse of Safety Issues
with AP1000 Shield Building,” Power Engineering, October 16, 2009,
http://www.pepei.pennet.com/displayZ_article/370134/6/ARTCL/none/none/1/NRC-informswestinghouse-of-safety-issues-with-AP1000-shield-building/, (accessed October 27, 2009);
“Westinghouse Could Suffer a Setback In Plans to Deploy its AP1000 Reactor After US
Regulators Required More Work on the Shield Building,” World Nuclear News, October 16,
2009, http://www.world-nuclear-news.org/print.aspx?id-26330, (accessed October 27, 2009).

207

208

Appendix 6: Select Portion of the Energy Policy Act of 1992 431
Title XXVIII—Nuclear Plant Licensing
Sec. 2801. Combined Licenses.
Section 185 of the Atomic Energy Act of 1954 (42 U.S.C. 2235) is amended . . .
(3) by adding at the end the following new subsection:
“b. After holding a public hearing under section 189a. (1)(A), the Commission shall
issue to the applicant a combined construction and operating license if the application
contains sufficient information to support the issuance of a combined license and the
Commission determines that there is reasonable assurance that the facility will be
constructed and will operate in conformity with the license, the provisions of this Act,
and the Commission’s rules and regulations. The Commission shall identify within the
combined license the inspections, tests, and analyses, including those applicable to
emergency planning, that the licensee shall perform, and the acceptance criteria that, if
met, are necessary and sufficient to provide reasonable assurance that the facility has
been constructed and will be operated in conformity with the license, the provisions of
this Act, an the Commission’s rules and regulations. Following issuance of the combined
license, the Commission shall ensure that the prescribed inspections, tests, and analyses
are preformed and, prior to operation of the facility, shall find that the prescribed
acceptance criteria are met. Any finding made under this subsection shall not require a
hearing except as provided in section 189 a. (1)(B).
Sec. 2802. Post Construction Hearings on Combined Licenses.
Section 189 a (1) of the Atomic Energy Act of 1954 (42 U.S.C. 2235) is amended . . .
(2) by adding after subparagraph (A) the following new subparagraph:
(B)(i) Not less than 180 days before the date scheduled for initial loading of fuel into a
plant by a licensee that has been issued a combined construction permit and operating
license under section 185 b., the Commission shall publish in the Federal Register notice
of intended operation. That notice shall provide that any person whose interest may be
affected by operation of the plant, may within 60 days request the Commission to hold a
hearing on whether the facility as constructed complies, or on completion will comply,
with the acceptance criteria of the license.
(ii) A request for a hearing under clause (i) shall show, prima facie, that one or more of
the acceptance criteria in the combined license has not been, or will not be met, and the
431

Energy Policy Act of 1992, H.R. 776, http://thomas.loc.gov/cgibin/query/F?c102:1:./temp/~mdbs0MIIy3::, (accessed November 12, 2008).

209

specific operational consequences of nonconformance that would be contrary to
providing reasonable protection of the public health and safety.
(iii) After receiving a request for a hearing under clause (i), the Commission
expeditiously shall either deny or grant the request. If the request is granted, the
Commission shall determine, after considering petitioners’ prima facie showing and any
answers thereto, whether during a period of interim operation, there will be reasonable
assurance of adequate protection of the public health and safety. If the Commission
determines that there is such reasonable assurance, it shall allow operation during an
interim period under the combined license.
(iv) The Commission, in its discretion, shall determine appropriate hearing procedures,
whether informal or formal adjudicatory, for any hearing under clause (i), and shall state
its reasons therefore.
(v) The Commission shall, to the maximum possible extent, render a decision on issues
raised by the hearing request within 180 days of the publication of the notice provided by
clause (i) or the anticipated date for initial loading of fuel into the reactor, whichever is
later . . .

210

Appendix 7: Probabilistic Risk Assessment
Probabilistic Risk Assessment (PRA) traces it origins to the Fault Tree Analysis
(FTA) employed by Bell Labs in 1961 to study the Minuteman Launch Control System
and later by Boeing to study the entire Minuteman Missile System. FTA became a
mechanism for analyzing the safety of physical systems, based on reliability theory and
probability theory. 432 About the same time, McDonald Douglas developed Failure Mode
and Effects Analysis (FMEA). Concern over a change in the design of a rear cargo door
prompted concerned engineers to issue a document outlining the problem with the change
and potential for disastrous consequences. 433 The engineers explained how, when, and
why the door might fail. The FTA and FMEA techniques proved so valuable in the
aerospace industry that they were soon adopted by the auto industry, the chemical
industry, and even the U.S. railroad system.
PRA builds on those early failure models. Instead of just looking at failures, PRA
examines the potential outcomes (or consequences) of an initiating event. The initiating
event could be an equipment failure, a power outage, or even an incorrect choice of
action in a given situation. PRA then constructs an event tree, a logical network that
starts with the initiating event and progresses through a series of branches (Top Events)
432

Ericson, Clifton A. II, “Fault Tree Analysis—A History,” The Boeing Company,
Seattle, WA, 1999, http://www.fault-tree.net, (accessed May 10, 2009), p. 1; Keller,
William, and Mohammad Modarres, “A Historical Overview of Probabilistic Risk
Assessment Development and its Use in the Nuclear Power Industry: A Tribute to the
Late Professor Norman Carl Rasmussen,” Reliability Engineering and System Safety,
Vol. 89, 2005, pp. 271 – 285.
433

“Failure Modes and Effects Analysis (FEMA),”
http://www.fmeainfocentre.com/updates/dec08/Failure%20Modes%20and%20Effects%2
0Analysis%20from%20Superfactory%20Excellence%20Program.PDF, (accessed May 6,
2009).

211

to the end states. The choice made at each branch results in a “success” or “failure”,
which then leads to the next decision point in the network. Assigning a probability to
each branch in the network allows the calculation of the end consequences of the event.
Figure 14 provides a simple example of an event tree.

212

Figure 14: Event Tree Example
Initiating
Event

Light Changes

Consequence

Top Events

Truck Stops

Brakes
Applied

Emergency
Brake
Applied

Evasive
Action
Taken

Truck Stops

Probability
No problem

0.9

No problem

0.0999

p = 0.9
Brakes Work
p = 0.999
Truck
Continues

Brake
Works

p = 0.10

p = 0.5
Brakes Fail
p = 0.001

Need to get brakes
checked

0.00005

Truck
Avoided

Need to be towed

p = 0.9

and get brakes checked

0.000045

Truck Hit

A major accident

0.000005

Brake Fails
p = 0.5

p = 0.1

Figure 14: Sample Event Tree Diagram
Source: Adapted from “Event Tree Analysis: Configuration Control and Assessment STP Nuclear Operating Company” 434

434

“Event Tree Analysis: Configuration Control and Assessment,” PowerPoint Presentation, STP Nuclear Operating Company.

213

The nuclear power industry greatly increased its use of PRA after the Three Mile
Island accident in 1979. The aim was to calculate the frequency of a core damaging
event (such as a meltdown) or a large release of radiation that might endanger the public.
The PRA began by looking at the key components of each plant and the series of actions
(or inactions) that could lead to a reactor shut-down. In 1995, the NRC issued a policy
statement on the use of PRA in its nuclear regulatory activities. 435 The NRC advocated
the use of PRA to complement its traditional defense-in-depth approach to safety, as a
tool to support its regulatory requirements and guidelines, and to promote “stability,
efficiency, and predictability” in its regulatory decisions.
Over time, PRA has evolved to include more and more components of the plant,
and updated to better reflect the actual probability of each branch of the tree, based on
increased industry experience. Building on these improvements, analysts typically model
about 2000 different nuclear power plant components and have estimated the annual
frequency of a core-damaging event to be in the range of 10-5 to 10-4, but with significant
uncertainty. The frequency of a large radiation release from containment typically is
estimated to be about an order of magnitude smaller. 436
The engineers and operators at U.S. utilities rely on PRA for much more than just
calculating core damage and radiation release frequencies. PRA has allowed them to
evaluate the importance of various components in protecting the reactor and to categorize
each according to whether it is significant to the safety of the plant. For example, a valve
435

“Fact Sheet on Nuclear Reactor Risk,” U.S. NRC, www.nrc.gov/reading-rm/doccollections/fact-sheets/reactor-risk.html, (accessed May 15, 2009).
436

“Risk 101: Basic Training, ESP-100.65,” STPEGS, Summer 2008, p. 15; Rick Grantom, The
South Texas Project, Telephone Interviews, Spring 2009; Dana Kelly, Idaho National Laboratory,
Conversation of January 16, 2010.

214

may not be directly related to emergency core cooling systems or other safety systems,
but its function may be deemed to be significant in the safe function of the reactor. By
looking at each component in that way, utilities can focus their most rigorous
maintenance activities on those components that are most critical to safety and can
perform less exacting maintenance inspections on those of less significance. PRA
empowers utilities to manage their resources in a risk-informed manner.
Understanding the risk associated with actions and equipment, and how the
various components tie into overall plant performance, allows for better decision making
about taking components out of service for repair or replacement. Work can be
scheduled so as to minimize the impact on safety. In addition, when the work has been
completed, the new operational data can be compared with the data that served as the
input to the risk analysis. Data that has been gathered for the PRA can serve as the
baseline of operations against which future performance is evaluated.
Events outside the nuclear power plant that might negatively affect operations can
also be included in a PRA. High winds, fires, earthquakes, and flooding can be
incorporated into the analysis to determine their potential impact and what actions might
need to be taken to prevent core damage if they did occur.
PRA can be used as input to the revision of safety standards and regulations.
During the early years of the nuclear power industry in the U.S., the NRC had established
standards based on its limited experience with small sized reactors and the input of
reactor designers and lawyers. In the mid-1990s, the NRC issued a Maintenance Rule
(10 CFR 50.65) for commercial nuclear power plants based on risk analysis and actual
operating data. The Rule permitted an increasing number of maintenance activities to

215

occur during normal operations—if safety was not compromised, the plant would not
have to be shut down. That change meant that reactors could stay on line, producing
electricity, and increasing their capacity factors to levels not seen in the U.S. before.
Work currently is underway to include the human element in PRA. Although
machines operate fairly consistently over time, people make errors in judgment,
deliberately choose to not follow procedures, and respond emotionally rather than
logically when under stress. Human Reliability Analysis (HRA) examines the likelihood
of particular human actions and how those actions can lead to hazardous situations or
adversely impact safety. For example, at nuclear power plants, HRA might look at the
probability that an operator would fail to open a valve when faced with a problem in the
core cooling system. Operator training could be revised to reduce the probability if the
number were deemed too high, or a back up system could be installed to insure the valve
would open as needed.
PRA also has been incorporated into the design and certification process for new
nuclear reactor design. 437 For example, the technique was used to develop risk
assessments for the Westinghouse AP1000. Data from the current fleet of reactors was
used as input for the components that would be similar in the old and new Westinghouse
designs. For totally new systems, computer simulations together with small-scale model
testing in labs were used to develop the likelihood of component failures. In addition, the
NRC required each company/utility submitting a COL application to conduct a sitespecific PRA. Risk also has informed the Inspections, Tests, Analyses, and Acceptance
Criteria (ITAAC) developed for the systems and programs at each new facility. The
437

C. J. Fong, Nuclear Regulatory Commission Region II Construction Inspection Organization,
Telephone Interview of May 14, 2009.

216

ITAAC specifies which factors are most safety critical and will be the focus of
inspections during construction. Since the NRC, reactor designers, and utilities all are
involved in establishing the ITAAC, there will be more certainty about the requirements
and more consistency from inspection to inspection than there was during the previous
round of reactor construction.
Whether the new plants will incorporate PRA into their daily operations remains
to be seen. Using a risk informed approach would give each plant more flexibility in how
it meets the NRC requirements versus having to abide by the strict NRC rules. But
performing and updating PRAs does require money and special skills. Some plants, like
South Texas, feel the investment is worth the cost, but others do not. Some may decide
to bring the new plants on line adhering to the NRC rules and then move to PRA-based
method once operational. At this time, the NRC is allowing the licensee of existing
facilities to choose the approach that best suits their needs and resources. 438 New plants
will be required to have a full-scope PRA and will be required to keep it up to date. 439
Probabilistic Risk Assessment is a quantitative tool that forces its users to break
down complex systems into their component parts, to look at the interrelationships
between those parts, to understand which components are vital to the safety of the
system, and to assess the likelihood that something will or will not function as expected
(potentially leading to a hazardous consequence). PRA permits wise allocation of
resources to the areas deemed most critical. It allows for monitoring of performance and
thus for information based decision-making. And it can be used to inform practices,

438

Ibid.

439

Kelly.

217

procedures, standards, and regulations. PRA can make current and future nuclear
operations more effective, efficient, and less risky.

218

Appendix 8. Interview Questions
Interviewee Background
What was your educational background?
How did you become involved with nuclear power?
Have you worked elsewhere in the energy industries?
How did you come to work in your present location/position?
The decision to apply to the Nuclear Regulatory Commission (NRC) for a
Construction and Operating License (COL)
Can you tell me when your company started to consider making an application for a
license to construct and operate a new nuclear power plant?
When did the discussion move from “whether” to construct to “when” to build?
What do you consider to be the primary factor(s) behind your company’s recent
application to build a new nuclear power plant?
What other factors contributed to that decision?
To probe specific topic areas, as necessary:
How important was it to your company’s application that Congress extended the PriceAnderson Indemnity Act?
How important to your company’s application were the loan guarantee programs passed
as part of the Energy Policy Act of 2005?
How important to your company’s application was the Nuclear Regulatory Commission’s
revision the licensing process--allowing applicants to receive a construction and
operating license at the one time?
The NRC revised its licensing process in the 1990s. What issues led your
company to wait until __________ to submit an application?
Has the volatility in prices of fossil fuels affected your company’s decision to apply for a
license to build a new nuclear power plant?
The price of uranium also has been rising in the past decade. Is that a concern as
your company embarks on such an expensive project?

219

Even though many support nuclear power as a means of freeing the United States from
excessive fuel imports, the World Nuclear Association indicates that the United States
possesses only 6% of the world’s known recoverable supply of uranium. Another 8%
lies in Canada.
How does your company view the security of ample uranium supplies?
Does it matter to your company whether uranium ores are located in the United
States/North America?
What about processing of uranium from the raw ore to fuel rods ready to load into
reactor?
To what extent did the contribution of fossil fuel to greenhouse gas emissions and to
global climate change affect your company’s decision to submit a construction and
operation license application?
As part of the Energy Policy Act of 2005, the EPA and NRC announced “Delay Risk
Insurance” to protect applicants against delays in approving nuclear power plant
construction applications. That insurance only benefits the first six applicants. Your
company is number ____________ in the queue.
Could you tell me how the availability of Delay Risk Insurance affected your
company’s decision as to if and when it would submit its application to the NRC?
Reactor Design Issues
Can you tell me how the availability of approved standard designs for new reactors
affected your company’s decision to build a new nuclear power plant?
The NRC approved several new nuclear power plant designs, hoping that
applicants would choose those designs, thus speeding up and simplifying the application
review process. Your company has selected a design that is not yet approved by the
NRC. Do you think that choice will impact the approval of your combined construction
and operating license? If so, in what way(s)?
Will the fact that your company has chosen an approved (or non-approved) design
affect your ability to secure financing for the project?
Will the choice of an untried reactor/plant design affect your company’s ability to
complete the facility on schedule and on budget?
Can you tell me how your company decided on the size (in MW) of the new
nuclear plant?
Did your company consider smaller, modular plants, like those now used
in France?

220

If so, what factors led your company to decide on the larger
design?
What challenges to you foresee in bringing such a large plant
successfully on-line?
In general, what will be among the biggest challenges your company will face in
constructing a new nuclear reactor/plant?
Several articles have indicated that the availability of parts, especially the ultra-heavy
steel parts, may be an issue when construction begins in earnest.
How is your company dealing with the challenges of this and other supply chain
issues?
Could you tell me how your company came to select (a) a site already occupied by an
existing reactor rather than a new site for the reactor, or (b) a new site for the reactor
rather than a site already occupied by an existing reactor?
What were the pros and cons of each type of site that your company considered
for this project?
The Economic Climate
The site your company has chosen lies in a state where electricity is unregulated (or
regulated).
Can you tell me how regulation and non-regulation of electricity markets affected
your company’s decision to invest in nuclear power at this time?
How might the current economic downturn in the United States and around the globe
affect your company’s decision to construct a new nuclear power plant?
Can you tell me if the election of a Democrat (Obama) as President rather than a
Republican will affect your company’s decision to build a new nuclear power plant?
Wrap-up
Can you tell me when and how your company will make the final decision on whether or
not to initiate construction of a new nuclear power plant?
At this time, can you tell me the likelihood that your company will indeed
construct a facility?
What factor(s) might cause your company to withdraw its application from NRC
consideration?

221

Can you tell me if you are optimistic or pessimistic about the future of nuclear power in
the United States?
What factor(s) most influence your position?
Are there any other questions I should have asked to gain a good understanding of the
decisions your company is making vis-à-vis nuclear power?

222

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October 7, 2008).

223

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