Nuclear Air Brayton Combined Cycle and Mark 1 Pebble Bed FluorideSalt-Cooled High-Temperature Reactor economic performance in a regulated electricity market

Nuclear Engineering and Design 323 (2017) 474–484

Contents lists available at ScienceDirect

Nuclear Engineering and Design
journal homepage: www.elsevier.com/locate/nucengdes

Nuclear Air Brayton Combined Cycle and Mark 1 Pebble Bed FluorideSalt-Cooled High-Temperature Reactor economic performance in a
regulated electricity market
Charalampos Andreades a,⇑, Per Peterson b
a
b

University of California, Berkeley, 4118 Etcheverry Hall, Berkeley, CA 94720, United States
University of California, Berkeley, 4167 Etcheverry Hall, Berkeley, CA 94720, United States

h i g h l i g h t s
 Mk1 FHR performs favorably compared to both utility and IPP built NGCCs.
 Mk1 FHR main performance drivers: electricity price, NG price, and the discount rate.
 Mk1 is much more attractive in markets where NG prices are high compared to NGCCs.

a r t i c l e

i n f o

Article history:
Received 28 April 2016
Accepted 11 December 2016
Available online 29 December 2016
Keywords:
Nuclear economics

Nuclear Air Brayton Combined Cycle
Flexible nuclear
FHR
Regulated electricity market
NGCC

a b s t r a c t
Understanding the financial performance of an engineered system is a key step to its commercialization.
In this study, the economic performance of the Mk1 PB-FHR using a nuclear air combined cycle to produce base load nuclear power, and highly efficient peaking power with gas co-firing, was estimated for
a regulated electricity market structure. Initially, a survey of major U.S. nuclear utility holding companies’
financials was performed to estimate a credible range of input parameters. In combination with the main
cost parameters of the Mk1 estimated in a companion paper, a base case analysis was performed, demonstrating the economic attractiveness of the Mk1. A sensitivity study demonstrated that the main metrics
of concern were electricity price, natural gas price, and the discount rate. These all pointed to possible
ways to further reduce the Mk1’s investment risk, such as long term fuel contracts and improved construction management, in order to further increase the attractiveness of Mk1 deployment. Finally, a comparison between the Mk1 and two different natural gas combined cycle (NGCC) plants was made. The
Mk1 performance lies in between a utility built and an independent power producer built NGCC. The
Mk1 becomes a much more attractive investment than conventional NGCCs in markets where natural
gas prices are high.
Ó 2016 The Authors. Published by Elsevier B.V. This is an open access article under the CC BY-NC-ND
license ( />
1. Introduction
One of the most important aspects of designing a new commercial technology is understanding its revenues and long term economic viability. There are certain instances where an investor or
business is willing to accept a loss on a specific product (e.g. loss
leaders, technical displays), but in general the aim is to create value
and generate profit in the long term. The profit of a product
depends on two specific components, namely cost and revenue,
the difference between the two being the profit/loss. This paper
assesses revenues for Mark-1 Pebble Bed, Fluoride Salt Cooled
⇑ Corresponding author.
E-mail addresses: (C. Andreades), peterson@nuc.
berkeley.edu (P. Peterson).

Reactors (Mk1 PB-FHRs) coupled to nuclear air combined cycle
(NACC) power conversion (Andreades et al., 2014a, 2016).
Narrowing our focus to the electricity sector, the main market
of the FHR and NACC (Mk1), it is important to understand the fundamentals of this sector’s operation and the ways in which it has
evolved over its lifetime. Here we focus on the U.S. electricity sector, although the conclusions can be generalized to other countries.
During the nascent years of the electricity industry at the turn of
the 20th century, U.S. electric utilities operated in a fiercely competitive environment, competing primarily in price with gas lighting and self-generation. There was discussion of appropriate rate
structures, such as time-of-use and block pricing, however the
need for stability and investor attractiveness pushed industry
pioneers, such as Samuel Insull, to promote demand charges and
government regulation of utilities as protected monopolies. This

/>0029-5493/Ó 2016 The Authors. Published by Elsevier B.V.
This is an open access article under the CC BY-NC-ND license ( />

475

C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

structure, in which utilities are guaranteed cost recovery at a regulated rate – cost plus x – allowed them to be shielded from competition, take advantage of economies of scale, and expand. Thus
was the status quo for the next seven decades. Around the
1990s, an interest in electricity market liberalization and deregulation took shape due to success in deregulating other industries,
such as telecommunications, trucking and commercial aviation,
and a resurgence in competitive pricing in electricity markets
was in vogue. This shifted electricity pricing away from average
cost (AC) based to marginal cost (MC) based. The changing nature
of modern electricity markets was and remains compounded by
the large scale introduction of intermittent renewable energy
sources. Flexible and quickly ramping capacity is needed to maintain grid stability, since traditional fossil fuel sources have physical

ramp constraints and battery reserves are not well suited to utility
scale capacities and demands.
The Mark 1 (Mk1) NACC is a novel power conversion system
based on a modified General Electric (GE) 7FB natural gas (NG) turbine. The turbine is retrofitted to accept external heating from a
heat source in the range of 600–700 °C, in this application an
FHR, while also maintaining its ability to combust NG or other
combustible fuel. When coupled to the 232 MWt Mk1 PB-FHR,
NACC provides 100 MWe of baseload electricity with a 42% efficiency, and a boosted power output of 240MWe under NG cofiring with a NG-to-electricity conversion efficiency of 66%, well
above current state of the art NGCCs. A full technical description
of the NACC can be found in Andreades et al. (2014b, 2014c). The
NACC, with its ability to peak on-demand and provide flexible
capacity make it an attractive and well suited candidate for the
current and future low carbon electricity markets, with high penetration of intermittent renewable energy sources. To assess the
Mk1 economic allure vis-à-vis its operating and physical benefits,
this study aimed at initially quantifying the Mk1’s revenue under
certain hypotheses and constraints in a regulated electricity market. A description of the methodology used to perform the revenue
estimation is given, followed by a summary of the relevant operating and cost inputs from a companion paper (Andreades, 2015).
The revenue and profitability results are then presented, followed
by discussion of the Mk1 results and a comparison made to its
main competitors.
2. Methodology
In order to create a regulated market revenue model, an industry standard commercial software package, THERMOFLEX/PEACEÒ,
was used (Thermoflow). Once a baseline NACC configuration was
established based on the Mk1 PB-FHR commercial point design
(Andreades et al., 2014a, 2016), and as detailed in Andreades
et al. (2014b, 2014c), relevant cost estimates were given. A market
survey of major U.S. nuclear utilities was performed to obtain a
plausible range of financing and electricity market data. A base
case was run with average values to establish a baseline reference,
followed by a sensitivity study on each parameter separately. Two

additional cases were run, an ‘optimistic’ and a ‘pessimistic’ one, in
order to bound the results. Finally, a comparison was carried out
between the NACC and a NGCC power plant based on the GE 7FB
of similar power output, in order to establish how well the proposed design performed against its assumed main competitor. All
currency units are set to 2014 USD.
3. Input data
The first step to performing a profitability analysis is assessing
costs of the system in question, as given by Eq. (1).

ProfitLossị ẳ Rev enue À Cost

ð1Þ

The relevant costs for the Mk1 were estimated in a companion
paper and a summarized version is presented in Table 1.
The next step is to appropriately identify and estimate financing
numbers and structures that fit such a project and as required for
input by THERMOFLEX/PEACEÒ’s, ‘Economic and regional costs’ tab.
Some basic operating assumptions were made. The Mk1 is
anticipated to have a 60 year lifespan; however, THERMOFLEX/
PEACEÒ is limited to a 40 year assessment. In lieu, one can simply
extrapolate the 40 year results to a 60 year lifetime. For the purposes of this study and for added conservatism a 40 year lifetime
was assumed.
The first year of plant operation was assumed to be 2021, following an assumed 5-year construction period, for a 12-unit plant.
THERMOFLEX/PEACEÒ does not account for staggered construction/operation which would provide added realism and thus
results are conservative as initial revenue is generated at a later
date, rather than as individual units come online. Such a modeling
approach can be considered as a counterbalance to potential construction delays.
The NACC is anticipated to operate in a load-following mode
due to its flexible capacity provided by its ability to produce peaking power by injecting NG or other liquid and gaseous fuels when

quick ramping is needed by the electricity grid. For this study it
was assumed that the 12-unit Mk1 NACC station ran at either
1200 MWe nuclear capacity or at a full 2832 MWe co-fired capacity.
The capacity factor of the plant was assumed to be the 10-year
nuclear industry average of 90%, with range between 80% and
95% (Nuclear Energy Institute, 2014). The Mk1’s online refueling
capability might enable a higher capacity factor, but current industry average was used for the base case instead for conservatism.
Typically, nuclear installation depreciation terms are set at
15 years (Department of Commerce Bureau of Economic Analysis,
2004). The Nuclear Energy Institute is proposing lowering this
term to 7 years, as it affects a plant owner’s tax expense (Fertel,
2004). A shorter depreciation term allows for a larger accounting
expense each year and therefore reduced taxes in earlier years. A
30 year high was used for the depreciation range.
Debt terms for nuclear facilities are typically set at 15 years
(OECD-NEA, 2009; IAEA, 1993). Longer terms allow for longer periods to repay and service the debt and are therefore more attractive.
A 30 year maturity date was used on the high side, while the
15 year term was used as the base and lower range.
The following three financing components, namely debt percentage, debt interest rate, and discount rate, are usually highly
project specific and in many cases confidential to the parties

Table 1
Overview of Mk1 costs.
Description
Capital construction costs
Preconstruction costs
Total direct cost
Indirect cost
Total contingency
Total capital investment

Specific capital investment
(nuclear)
Specific capital investment (CF)
Production Costs
Total annual O&M
Fuel cost (annual)
Decommissioning cost (annual)
Overall production cost
Marginal production cost

Single unit

12 Unit

80,484,991
214,846,727
142,462,635
71,461,872
509,256,225
5093

263,622,515
2,578,160,727
1,709,551,614
857,542,468
5,408,877,325
4507

$
$

$
$
$
$/kW

2133

1870

$/kW

62,086,683
7,750,516
1,165,920
71,003,119
81.05

311,631,799
93,006,192
13,991,046
418,629,037
39.82

$
$
$
$
$/
MW h

Bolded numbers are the key comparison metrics used to compare electricity generation technologies.


476

C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

involved. Additionally, no major nuclear construction of new
plants beyond Vogtle in Georgia and VC Summer in South Carolina,
has happened in the United States the past two decades so reliable
or relevant numbers are in short supply. Although Watts-Bar 2 was
completed in 2015 with an approved cost of $4.7bn, it does not
provide relevant information since its construction began in 1972
with a 22 year hiatus between 1985 and 2007 (World Nuclear
Association, 2016). The approach taken to estimate these numbers
was to study and average the financial statements and fillings of
the major nuclear utilities, as shown in Table 2.
In order to use these numbers correctly, a corporate financing
structure rather than a project financing structure was assumed.
This assumption is particularly appropriate for small modular reactor stations like the Mk1 PB-FHR station, because the capital placed
at risk before initial electricity is delivered to the grid is substantially smaller than for conventional large reactor plants. Corporate
financing usually implies gentler financing terms and higher leverage since lenders have a recourse on the utility’s balance sheet, not
just the project itself.

Table 2
Major U.S. nuclear utility holding companies.
Name

NYSE

Number of plants

Exelon
Entergy
Duke
NextERA
TVA
Dominion
First Energy
Southern
XCEL
SCANA

EXC
ETR
DUK
NEE
TVA
D
FE
SO
XEL
SCG

15
8
6
5
3
3

3
3
2
1

Assets ẳ Liability ỵ Equity

2ị

Next, debt interest rate and tax rate were obtained from nuclear
utility 10k filings. Finally, the discount rate was assumed to be the
rate of return to equity investors. To approximate the discount
rate, the weighted average cost of capital (WACC), as defined in
Eq. (3), was obtained from financial analysis companies
(GuruFocus.com LLC, 2015) and modified to yield our estimate.

WACC ¼

Equity
Liability
Á Cost equity ỵ
Cost liability 1 Taxrateị
Assets
Assets

3ị

The overall results for all major U.S. nuclear utility holding companies are presented in Table 3.
The three remaining inputs that were estimated were the price
of carbon tax and the prices of electricity and natural gas.

The price of carbon was assumed to vary between zero, to
reflect the current U.S. status quo, and 120 $/tCO2e as a ceiling
with a base of 40 $/tCO2e (Interagency Working Group on Social
Cost of Carbon, 2013). The natural gas price range was obtained
from the historical range of prices from the past 15 years
(Chicago Mercentile Exchange, 2015). An electricity price range
was obtained from the 2015 Annual Energy Outlook (U.S. Energy
Information Administration, 2014). The input parameters are summarized in Table 4.
A final note is that escalation rates for costs were assumed to be
constant and equivalent to inflation.
4. Results

49a

Total

Debt percentage was estimated from each company’s most
recent public annual balance sheet from the basic accounting
Eq. (2).

a
Number of plants is different to number of reactors. Each nuclear plant can have
one or more reactors on site.

The results for the base case assumptions are presented in
Table 5, for both baseload and co-fired operation.
What is apparent from the results in Table 5 is that under constant full capacity operation the Mk1 seems to be an attractive

Table 3
Summary of financial data for major U.S. nuclear utility holding companies.

a

Name

NYSE

Total assets [bn $]

Total equity [bn $]

Equity [%]

Debt [%]

Tax rate [%]

WACC [%]

Cost of debt [%]

ROR [%]

Exelon
Entergy
Duke
NextERA
TVA
Dominion
First Energy

Southern
XCEL
SCANA
Average

EXC
ETR
DUK
NEE
TVAa
D
FE
SO
XEL
SCG

86.8
46.5
120.7
74.9
45.6
54.3
52.2
70.9
37.0
16.9
60.6

22.8
10.1

40.9
19.9
6.10
11.60
12.40
20.90
10.20
5.00
16.0

26.27
21.72
33.89
26.57
13.38
21.36
23.75
29.48
27.57
29.59
25.40

73.73
78.28
66.11
73.43
86.62
78.64
76.25
70.52

72.43
70.41
74.60

32.22
30.83
36.27
32.02

4.50
4.57
4.08
5.18

7.58
9.75
7.22
11.25

29.21
4.825
32.83
33.85
31.84
29.30

4.56
4.32
3.46
4.34

4.49
4.40

5.02
4.53
3.88
4.39
7.25
4.90
4.50
3.46
4.09
5.02
4.70

8.58
4.44
6.18
8.63
7.03
7.90

Not a publicaly traded company, Data from 2014 10K filings.

Table 4
Financing and market input parameters.

Capacity factor
Depreciation
Debt term

Debt%
Debt interest
Discount rate
CO2 price
Natural gas price
Electricity price

Base

Low

High

Unit

90
15
15
74.6
4.7
7.9
40
4.45 (4.22)
0.103

80
7
–
66.1
3.5

4.4
0
2.23 (2.11)
0.062

95
30
30
86.6
7.3
11.2
120
15.6 (14.8)
0.132

%
yrs
yrs
%
%
%
$/tCO2e
$/MMBtu ($/GJ)
$/kW h


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C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

investment, with a net present value (NPV) of $18.8bn, a levelized
cost of electricity (LCOE) of $0.045/kW h and a breakeven price of
NG of $21.6/GJ (22.8 $/MMBtu), i.e. the price of NG up until which
the plant remains profitable. On the other hand, under base load
operation the Mk1 is an unprofitable investment and is thus discounted for the rest of this analysis. A note to make is that the
Mk1 will run in its peaking mode only when prices of electricity
are above the price where electricity revenues exceed natural gas
costs, and it is quite unlikely that it will run at full capacity at all
times.
The results for the co-fired deviating cases are presented graphically for compactness in Figs. 1–5. The effect of each input variable
on selected major dependent variables is illustrated.

Fig. 1 demonstrates that NPV is most sensitive to discount rate,
electricity price, and NG price. Electricity price affects the revenue
cash flow of the Mk1, with reduced prices resulting in reduced revenue. NG prices affect the cost stream of the Mk1, with increased
prices reducing profit margin. The results vary dramatically as
parameters vary. Other input parameters have much smaller, yet
not negligible effects. A counterintuitive result is the relatively
small effect of an imposed carbon tax (12% range in NPV from base
case) compared to the dominating parameters. The high conversion efficiency of NG to electricity allows the NACC to burn less
NG and thus reduce its carbon tax cost and thus mitigate a more
pronounced impact; however, if considered separately, an approximately 10% swing in NPV is still significant.

Table 5
Mk1 base case (40 $/tCO2e) economic performance under peaking and baseload operation.

Plant capacity
Annual electricity exported
Annual heat exported
Annual fuel imported (NG)

Annual water IMPORTED
Annual CO2 emission
Total investment
Specific investment
Initial equity
Cumulative net cash flow
Internal rate of Return on Investment (ROI)
Internal rate of Return on Equity (ROE)
Years for payback of equity
Net present value
Levelised cost of electricity
Break-even NG LHV price @ input electricity price

Co-fired

Baseload

Units

2892
21,753
0
72,067
7570
1344
5,437,727,000
1971
1,381,183,000
109,520,200,000
25.037

63.769
1.68
18,805,650,000
0.0454
22.8 (21.6)

1200
9076
0
0
3825
0
5,148,817,000
4473
1,307,800,000
9,763,285,000
5.16
6.02
23.16
À1,285,687,000
0.12
2.68 (2.53)

MW
10^6 kW h
TJ
TJ LHV
10^6 L
ktonne
$

$/kW
$
$
%
%
years
$
$/kW h
$/MMBtu ($/GJ)

Fig. 1. Net present value of project.


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C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

Fig. 2 demonstrates that return on investment (ROI) is most sensitive to NG price, electricity price, and capacity factor for co-fired
operation. This makes sense since electricity price and capacity fac-

tor determine the revenue stream, while NG price affects the cost
stream and thus the time and amount needed to pay back investors
in a timely manner, in turn affecting return on investment.

Fig. 2. Return on investment of project.

Fig. 3. Levelized cost of electricity of project.


C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

Fig. 3 illustrates that the LCOE is most sensitive to NG price, discount rate, and to a lesser extent carbon price. A carbon tax is a
price adder by definition. Higher discount rate increases LCOE by

479

increasing returns demanded by investors. NG price is directly
linked to the cost of producing electricity. It is imperative to note
that only high NG prices push LCOE to exceed 0.05$/kW h, but on

Fig. 4. Years to payback equity.

Fig. 5. Break-even natural gas price at input electricity price.


480

C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

the other hand can lower it down below 0.04$/kW h. All other
parameters keep LCOE within that range.
As NG price increases it keeps imposing a larger production
cost, up to a certain point where it then makes the plant unprofitable (i.e. the break-even price of NG). If electricity market feedback is considered, the BL capacity provided by nuclear heat will
have a larger profit margin as NG price increases, since the price
will be set by competing NGCCs or GTs, as the NACC’s co-fired
capacity has a much higher thermal efficiency.
Fig. 4 shows that NG price and electricity price affect years of
payback of equity by shifting the profit margin on cost and revenue
for production costs. All other variables have negligible effects and

a range of payback on co-fired operation between a year and two
years.
Fig. 5 depicts the effects of discount rate, electricity price, and
capacity factor on the break-even NG price at input electricity
price. As discount rate increases, the NG price threshold is lowered,
thus becoming more restrictive. As electricity price and capacity
factor increase, so does the NG threshold, meaning that the cofired Mk1 can remain profitable even at higher NG prices, up to
$31/GJ.
The bounding cases, where all input parameters were set to
either optimal or worst case, are presented in Table 6. What
becomes immediately clear is that the range of results is too broad

Table 6
Bounding case financial results for Mk1.

Annual electricity exported
Annual fuel imported (NG)
Annual CO2 emission
Total investment
Specific investment
Initial equity
Cumulative net cash flow
Internal rate of Return on Investment (ROI)
Internal rate of Return on Equity (ROE)
Years for payback of equity
NPV
LCOE
Break-even fuel LHV price @ input electricity price

Optimistic

Base

Pessimistic

Units

22,990
76,162
8000
5,437,727,000
1970.8
728,655,500
180,443,800,000
39.433
242.372
0.4203
64,084,140,000
0.0302
32.84

21,753
72,067
7570
5,437,727,000
1970.8
1,381,183,000
109,520,200,000
25.037
63.769

1.68
18,805,650,000
0.0454
21.6

19,865
135,557
6443
5,437,727,000
1970.8
1,843,389,000
À20,482,060,000
0
0
N/A
À6,094,365,000
0.0948
4.878

10^6 kW h
TJ LHV
ktonne
USD
USD/kW
USD
USD
%
%
years
USD

USD/kW h
USD/GJ

Fig. 6. GE 7FB gas turbine and HRSG THERMOFLEX/PEACEÒ schematic.


C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

481

Fig. 7. Three pressure steam turbine for combined cycle THERMOFLEX/PEACEÒ schematic.

Table 7
NGCC operation and financial parameters.

Lead time
Project Life
Depreciation
Contingency
Debt term
Debt percentage
Debt interest rate
Tax rate
Discount rate
Overnight cost
Total overnight cost
Variable O&M
Fixed O&M
Capacity factor

IPP

Utility

3
20
15
8
9
70
8.75
30
20
977
1055
3.32
15.61
87

3
30
15
8
30
50
7.75
30
10
977
1055

3.32
15.61
87

years
years
years
%
years
%
%
%
%
$/kW
$/MWh
$/kW/yr
%

to make any definitive conclusions, other than that both cases are
unlikely.

5. Discussion
What is distilled from the results in the previous section is that
three parameters recurrently affect the economic performance of
the Mk1, namely NG and electricity prices, and discount rate. Additionally, these parameters are mainly market and not operation
(capacity factor) driven. Although other variables should also be

kept in mind, they do not have as pronounced an effect as the
aforementioned. This leads us to concentrate on understanding
how one might try to positively affect each parameter, if at all

possible.
The price of NG or combustible fuel is to a large extent external
and can only be set advantageously through long term delivery
contracts, rather than being purchased on the volatile spot market.
In many international markets, natural gas prices are sufficiently
high that the Mk1 economics will be attractive.
Electricity price to a certain extent can be affected by bringing
on or taking off the Mk1’s flexible capacity, when the opportunity
cost might warrant it. However, there needs to be a strong consideration to avoid applying market power to manipulate spot prices
of electricity, since a full Mk1 plant has a significant peaking
reserve capacity.
The amount of remuneration demanded by equity investors,
namely through the discount rate, signals the risk perception of
the individual project in tandem with that of the industry as a
whole. What the Mk1 needs to accomplish to become attractive
is to convince investors of a superior risk profile vis-à-vis its competitors. Steady and added revenues from its flexible capacity,
reduced capital investment due to stacked construction and operation, economies of series due to factory production should all help
to reduce the risk profile of the Mk1. Furthermore, steady, manageable, and predictable costs should also be a priority.
On an industry front, nuclear needs to be perceived as investor
friendly, through streamlined regulation, improved construction
and supply chain management. A deeper elaboration on these
issues is beyond the scope of this study.


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C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

5.1. Comparison to conventional NGCC
In order to obtain a better perspective of the previous economic

results of the Mk1, a comparison between it and its competitors
was deemed necessary. The most obvious candidate to compare
the Mk1 to was an unmodified NGCC based on the GE 7FB. This
comparison essentially shows whether the Mk1’s more efficient
burning of NG during peak operation compared to a conventional
NGCC could make up for the added capital cost of the nuclear component of the system. A THERMOFLEX/PEACEÒ model using a five
2 Â 1GE 7FB and steam turbine configuration was used to match
the power output of the Mk1 at 2800 MWe, as shown in Figs. 6
and 7.
The main input parameters for the NGCC were selected from
industry averages of advanced NGCC from the Energy Information
Administration’s 2015 Annual Energy Outlook (U.S. Energy
Information Administration, 2015) and Alstom (Bozzuto, 2006)
and are presented in Table 7. A utility and independent power producer (IPP) financing structure were used to compare the two different scenarios of constructing NGCCs.

The base case results of the co-fired Mk1 were compared to
those of the NGCC and are presented in Table 8. A sensitivity study
was performed on the price of carbon, electricity price, and NG
price and compared to the Mk1 graphically in Figs. 8–10, with all
metrics being normalized to the values of the Mk1 base case.
Under base case assumptions with a 40 $/tCO2e carbon price,
the co-fired Mk1 compared favorably to both an IPP NGCC installation and a utility built NGCC. The Mk1 managed a NPV of 1$8.8bn
as compared to $4.4bn of an IPP NGCC and $12.7bn of a utility
NGCC. Return on investment was nearly double for the NGCCs
due to the smaller initial capital required compared to the Mk1.
The LCOE of the Mk1 was lower than an IPP NGCC and slightly
higher than a utility owned NGCC. The break-even price of NG,
i.e. the price of NG up until which the plant remains profitable,
was significantly higher than both NGCCs, demonstrating that
the Mk1 would perform very favorably in markets with high NG

prices, such as Europe and Japan. The main difference between
the IPP and utility NGCCs is the longer running period of the utility
plant, which led to more favorable financial results. This should
also be considered when looking at the results for the Mk1, since

Table 8
Financial performance of competitors under base case assumptions.

Annual electricity exported
Annual fuel imported (NG)
Annual CO2 emission
Total investment
Specific investment
initial equity
Cumulative net cash flow
Internal rate of Return on Investment (ROI)
Years for payback of equity
NPV
LCOE
Break-even fuel LHV price @ input electricity price

Mk1

IPP NGCC

Utility NGCC

Units

21,753

72,067
4033
5,437,727,000
1971
1,381,183,000
109,520,200,000
25.04
1.68
18,805,650,000
0.045
21.60
(22.81)

21,365
135,483
7684
2,959,311,000
1055
887,793,300
30,452,090,000
40.57
1.13
4,351,637,000
0.055
11.81
(12.47)

21,365
135,483
7684

2,959,312,000
1055
1,479,656,000
61,093,990,000
40.66
1.49
12,741,680,000
0.043
13.63
(14.39)

10^6 kW h
TJ LHV
ktonne
$
$/kW
$
$
%
years
$
$/kW h
$/GJ ($/MMBtu)

Fig. 8. Normalized financial parameters under electricity price variation.


483

C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

only two thirds of its operational lifetime were accounted for in
this study. An additional fact to consider is that the Mk1 managed
to produce more power with a smaller carbon footprint compared
to a NGCC of a similar size, due to its improved power conversion
efficiency and producing part of the power by non-emitting
nuclear fuel.
Changing electricity price can have a dramatic effect on the performance of plants as pointed out in the previous section. As

shown in Fig. 8, as electricity price increased all plants performed
better. All results were normalized to the Mk1’s base case results.
The IPP NGCC could not compete with the co-fired Mk1 on NPV
even under high electricity prices. The utility owned NGCC also
struggles to compete with Mk1 as electricity prices vary. The same
basic comparative outcomes as the base case still applied under the
electricity sensitivity study.

Fig. 9. Normalized financial parameters under NG price variation.

Carbon tax variaƟon

2
1.8
1.6

Normalized Value

1.4
1.2
1

0.8
0.6
0.4
0.2
0

Mk1

IPP UƟlity
NGCC NGCC
NPV

Mk1

IPP UƟlity
NGCC NGCC
LCOE

$120/tCO2

Mk1

IPP UƟlity
NGCC NGCC
ROI

$40/tCO2

$0/tCO2

Fig. 10. Normalized financial parameters under carbon tax variation.

Mk1

IPP UƟlity
NGCC NGCC

NG Price B.E.


484

C. Andreades, P. Peterson / Nuclear Engineering and Design 323 (2017) 474–484

Where a dramatic shift in comparative results was seen was
under NG price variation, the main fuel input and running cost
for the two NGCC plants, as depicted in Fig. 9. As NG prices were
increased, performance of the NGCCs fell significantly in all financial metrics. LCOE nearly doubled for both NGCC plants, NPV and
ROI became negative, i.e. making them a poor investment, and
the NG breakeven price fell quite significantly for both NGCCs.
The co-fired Mk1 managed to maintain positive financials under
all scenarios, pointing out that in a high NG price environment,
e.g. Japan or parts of Europe, it would be the better choice as
pointed out in a prior section.
Additionally, what is apparent from Fig. 10 is that a carbon tax
did not have a tremendous impact on financial results for the three
plants, and the comparative results remained the same as in the
co-fired base case.
A final note to make in this comparative study is that a more
accurate comparison for the Mk1 would have been between a combination of a conventional nuclear plant and a NGCC, since the Mk1

is a hybrid plant that performs the functions delivered by these
plants separately. However, due to the performance improvement
of the Mk1 compared to a standalone NGCC, the combined plant
comparison becomes redundant, since it also performs better than
a conventional nuclear power plant.
6. Conclusion
Understanding the financial performance of an engineered system is a key step to its commercialization. In this study, the economic performance of the Mk1 PB-FHR with NACC was estimated
under a regulated electricity market structure. Initially, a survey of
major nuclear utility holding companies’ financials was performed
to estimate a credible range of input parameters. In combination
with the main cost parameters of the Mk1 estimated in a companion paper (Andreades et al., 2014a), a base case analysis was performed, demonstrating the economic attractiveness of the Mk1. A
sensitivity study demonstrated that the main metrics of concern
were electricity price, natural gas price, and the discount rate.
These all pointed to possible ways to mitigate the co-fired Mk1’s
investment risk, such as long term natural gas (or other combustible) fuel contracts and improved construction management,
in order to make it a more attractive venture.
Finally, a comparison between the Mk1 and two different
NGCCs was made. The Mk1 performs favorably compared to both
a utility built and an IPP built NGCC, outperforming them in several
key metrics. The Mk1 becomes a much more attractive investment
in markets where natural gas prices are high compared to the
NGCCs. A caveat to mention in the results of this study is that a
40 year lifetime was modeled rather than the anticipated 60 year
lifetime of the Mk1, thus understating the Mk1’s economic perfor-

mance vis-à-vis the NGCCs. Future study might be merited in the
performance of the Mk1 in a deregulated electricity market as
described in the introduction and a more in-depth look at risk mitigation strategies for attracting investment.
Acknowledgments
This research was performed using funding received from the U.

S. Department of Energy Office of Nuclear Energy’s Nuclear Energy
University Program.

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