A Review of the Costs
of Nuclear Power
Generation
Prepared by Michael T. Hogue
Bureau of Economic and Business Research
David Eccles School of Business
University of Utah
February 2012
Cover Image by Melvin A. Miller of the Argonne National Laboratory. The first nuclear reactor was erected in 1942 in the West Stands section of
Stagg Field at the University of Chicago. On December 2, 1942 a group of scientists achieved the first self-sustaining chain reaction and thereby
initiated the controlled release of nuclear energy. The reactor consisted of uranium and uranium oxide lumps spaced in a cubic lattice imbedded in
graphite. In 1943 it was dismantled and reassembled at the Palos Park unit of the Argonne National Laboratory. (Image from Wikimedia Commons.)
Final Report
Published March 2012
A Review of the Costs of Nuclear Power
Generation
Prepared by Michael T. Hogue
Bureau of Economic and Business Research (BEBR)
David Eccles School of Business
University of Utah
Salt Lake City, UT 84112
Published March 2012
A Review of the Costs of Nuclear Power Generation
Michael T. Hogue
Table of Contents
1 Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
2 Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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3 Levelized Costs . . . . . . . . . . . . . . . . . . . . . . . . .
3.1 Construction . . . . . . . . . . . . . . . . . . . . . . . .
3.2 Fuel and Other Operations and Maintenance Costs
3.3 Operational Lifetime and Capacity Factors . . . . . .
3.4 Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.5 The Discount Rate . . . . . . . . . . . . . . . . . . . . .
3.6 Carbon Dioxide Emissions . . . . . . . . . . . . . . . .
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4 Levelized Costs for Combinations of Fuel and CO2 Emissions Prices . . . . . . . . . . . . . .
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5 Levelized Costs with Uncertain Fuel Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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6 Breakdown of LCOE for Variations on Base Cases . . . . . . . . . . . . . . . . . . . . . . . . . .
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7 Model of Uncertain Fuel Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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List of Figures
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Forecast gas prices, under the assumption that gas prices follow a geometric Brownian
motion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forecast coal prices, under the assumption that coal prices follow a geometric Brownian
motion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Histogram of levelized costs ($/MWh) of gas-fired generation. . . . . . . . . . . . . . . . .
Histogram of levelized costs ($/MWh) of coal-fired generation. . . . . . . . . . . . . . . . .
Levelized costs ($MWh) in the Scenarios I base case. . . . . . . . . . . . . . . . . . . . . . .
Levelized costs ($MWh) in the Scenarios II base case. . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) evaluated at overnight costs that are
greater or lesser than Scenarios I base-case overnight costs. . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) evaluated at overnight costs that are
greater or lesser than Scenarios II base-case overnight costs. . . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I low overnight case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II low overnight case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I high overnight case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II high overnight case. . . . . . . . . . . . . . .
Inflation-adjusted historic FOB prices per MMBTU of natural gas, 1950–2011. . . . . . .
Inflation-adjusted historic prices per MMBTU of bituminous coal, 1950–2010. . . . . . .
Inflation-adjusted historic prices per pound of uranium, 1995–2010. . . . . . . . . . . . .
Inflation-adjusted historic fuel prices, 1996–2011. . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) evaluated at fuel costs that are greater
or lesser than Scenarios I base-case fuel costs. . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) evaluated at fuel costs that are greater
or lesser than Scenarios I base-case fuel costs. . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) versus the operational lifetime of the
power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) versus the operational lifetime of the
power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) versus the lifetime capacity factor for
the power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) versus the lifetime capacity factor for
the power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) versus the hurdle rate (WACC) for the
power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) versus the hurdle rate (WACC) for
the power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) versus hypothetical charges on CO2
emissions ranging from 0 to $120 per ton. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) versus hypothetical charges on CO2
emissions ranging from 0 to $120 per ton. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I low fuel cost case. . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II low fuel cost case. . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I high fuel cost case. . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II high fuel cost case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I low CO2 cost case. . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II low CO2 cost case. . . . . . . . . . . . . . . .
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Levelized costs ($/MWh) in the Scenarios I high CO2 cost case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II high CO2 cost case. . . . . . . . . . . . . . . .
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List of Tables
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Levelized cost ($MWh) of gas-fired generation for various combinations of natural gas
and CO2 prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Levelized cost ($ MWh) of coal-fired generation over various combinations of coal and
CO2 prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I base-case assumptions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Base-case assumptions in Scenarios II. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basic findings of three influential studies on the economics of nuclear power. . . . . . . .
Calculating the discount rates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized cost of gas-fired generation over various combinations of natural
gas (columns) and CO2 (rows) prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized cost of coal-fired generation over various combinations of coal
(columns) and CO2 (rows) prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized cost of nuclear generation over various combinations of nuclear
fuel (columns) and CO2 (rows) prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized cost of gas-fired generation over various combinations of natural
gas (columns) and CO2 (rows) prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized cost of coal-fired generation over various combinations of coal
(columns) and CO2 (rows) prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized cost of IGCC (with 90 percent carbon capture and sequestration)
generation over various combinations of coal (columns) and CO2 (rows) prices. . . . . .
Scenarios II: Levelized cost of NGCC (with 90 percent carbon capture and sequestration)
generation over various combinations of natural gas (columns) and CO2 (rows) prices. .
Scenarios II: Levelized cost of nuclear generation over various combinations of nuclear
fuel (columns) and CO2 (rows) prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tabular representation of Figure 1: Simulated Natural Gas Prices. . . . . . . . . . . . . . . .
Tabular representation of Figure 2: Simulated Coal Prices. . . . . . . . . . . . . . . . . . . .
Percentiles of levelized costs for gas-fired generation. . . . . . . . . . . . . . . . . . . . . . .
Percentiles of levelized costs for coal-fired generation. . . . . . . . . . . . . . . . . . . . . .
Levelized costs ($MWh) in the Scenarios I base case. . . . . . . . . . . . . . . . . . . . . . .
Levelized costs ($MWh) in the Scenarios II base case. . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) evaluated at overnight costs that are
greater or lesser than Scenarios I base-case overnight costs. . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) evaluated at overnight costs that are
greater or lesser than Scenarios II base-case overnight costs. . . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I low overnight case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II low overnight case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I high overnight case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II high overnight case. . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) evaluated at fuel costs that are greater
or lesser than Scenarios I base-case fuel costs. . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) evaluated at fuel costs that are greater
or lesser than Scenarios I base-case fuel costs. . . . . . . . . . . . . . . . . . . . . . . . . . .
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Scenarios I: Levelized costs (in year 2011 dollars) versus the operational lifetime of the
power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) versus the operational lifetime of the
power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) versus the lifetime capacity factor for
the power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) versus the lifetime capacity factor for
the power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) versus the hurdle rate (WACC) for the
power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios II: Levelized costs (in year 2011 dollars) versus the hurdle rate (WACC) for
the power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) versus hypothetical charges on CO2
emissions ranging from 0 to $120 per ton. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Scenarios I: Levelized costs (in year 2011 dollars) versus hypothetical charges on CO2
emissions ranging from 0 to $120 per ton.. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I low fuel cost case. . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II low fuel cost case. . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I high fuel cost case. . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II high fuel cost case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I low CO2 cost case. . . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II low CO2 cost case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios I high CO2 cost case. . . . . . . . . . . . . . . .
Levelized costs ($/MWh) in the Scenarios II high CO2 cost case. . . . . . . . . . . . . . . .
Estimates of the GBM parameters for the coal and natural gas price models. . . . . . . . .
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1. EXECUTIVE SUMMARY
1
1. Executive Summary
This report presents an analysis undertaken by the Bureau of Economic and Business Research (BEBR)
on the cost of electricity generated from newly constructed nuclear power plants. The financial pros
and cons of nuclear power are measured against its chief fossil-fuel competitors—coal and natural gas.
The results of the analysis suggest that new nuclear power would be more costly than that from either
coal or natural gas, but that there are plausible scenarios under which nuclear power is less costly than
either coal or natural gas. Particularly important issues bearing on the cost of nuclear power vis-a-vis
coal and natural gas are the future prices of coal and natural gas, future regulations on carbon dioxide
emissions, more stringent ambient air quality standards, and the cost of constructing (but not the cost
of operating) new nuclear power plants.
Nuclear power also has a different risk profile than coal and natural gas. Because of the lack of
recent experience in building nuclear power plants in the U.S. there is considerable uncertainty surrounding the cost of new nuclear construction that would be realized in practice. Since construction
costs make up a large fraction of the total cost of nuclear power, construction cost uncertainty translates
into an important financial risk facing new nuclear power plants. This may be contrasted with a standard natural gas power plant, where fuel costs (the price of natural gas), but not construction costs, are
both subject to a great deal of uncertainty and represent a large part of total costs. Consequently, for
natural gas a key risk is fuel cost risk. Coal is intermediate, having greater fuel price risk than nuclear,
but less than natural gas; greater construction cost risk than natural gas, but less than nuclear. These
statements apply to the standard varieties of coal and natural gas plants currently operating in the U.S.
and newer but still relatively standard nuclear power technology.
The following are brief summaries of the findings from each of the major sections of the report.
Section 2 Scenarios This study requires specification of technical and financial characteristics of the
power plants considered as well as broad economic conditions. Two sets of project-level characteristics are utilized; one drawn from a 2009 report by the Massachusetts Institute of Technology
(MIT) and the other from a 2010 report published by the U.S. Energy Information Administration
(EIA). Economic conditions, including future inflation rates and prices for coal and natural gas
are based on EIA data. Scenarios are defined as combinations of power generation technology
(with its associated technical and financial characteristics) and economic conditions. For example, in what we refer to as Base Case I for nuclear power, the power plant is assumed to have a
nameplate capacity of 2200 megawatts, a construction cost of about $4.3 million per megawatt,
a lifetime of 40 years, to produce electricity at 90 percent of its nameplate capacity, etc. These
assumptions associated with each scenario are the inputs of a discounted cash flow analysis.
Section 3 Levelized Costs The levelized cost of electricity (LCOE) is the basic measure used to assess
the economics of each scenario. The LCOE is the minimum constant price a project must receive
on each unit of electricity it generates in order to recoup exactly the cost of producing that unit,
including a competitive return on investment. We determine the LCOE for each of the scenarios
described in Section 2. See Table 3 for Base Case I specifications and Table 4 for Base Case II
specifications.
The LCOE for each plant considered in Base Cases I and II is is shown in Figures 5 and 6 respectively and the accompanying Tables 19 and 20.
Section 3.1 Construction Construction costs are expenditures associated with acquiring and preparing the site of the plant and the materials and construction of the plant itself. The share of construction costs in total costs (capital intensity) is an important distinguishing feature of power
plant technologies, having implications for the financial risk profile of a power project.
2
A REVIEW
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Nuclear power plants are highly capital intensive. In addition, because of the lack of recent
experience building nuclear power plants in the U.S., considerable uncertainty surrounds what
construction costs would be in practice. These two facts combine to make construction costs a
key risk factor for new nuclear power. With much lower capital intensity and considerable recent
construction experience, construction cost uncertainty poses far less risk to natural gas plants.
Again, coal plants are intermediate.
Regarding the sensitivity of LCOE to construction costs, in Base Case I we find that an increase
of 50 percent in the cost of construction entails an increase of 36 percent in the overall cost of
nuclear power, but increases of only 8 percent and 22 percent, respectively, for natural gas and
coal-powered plants.
See Figure 7 and Figure 8 (or Table 21 and Table 22) for the overall sensitivity of LCOE to
construction costs in Base Cases I and II. See Figure 9 and Figure 10 (or Table 23 and Table 24)
for the breakdown of LCOE when construction costs are lower than what is assumed in Base Cases
I and II. See Figure 11 and Figure 12 (or Table 25 and Table 26) for the breakdown of LCOE when
construction costs are higher than what is assumed in Base Cases I and II.
Section 3.2 Fuel and Other Operations and Maintenance Costs A variety of periodic costs
are incurred once construction is complete and a project enters its operations phase. These are
classified as fuel costs, variable costs, fixed costs, and incremental capital costs. Fixed costs and
incremental capital costs depend only on the plant’s generation capacity, while fuel costs and
variable costs depend only on the fraction of the plant’s capacity that is utilized.
Compared to coal- and gas-based power, the cost of nuclear power is far less sensitive to the cost of
fuel. For example, in Base Case I, a doubling of the cost of nuclear fuel leads to an approximately
10 percent increase in the total cost of nuclear power generation. Doubling the cost of coal and
natural gas leads to increases of approximately 32 and 77 percent, respectively, in the cost of coaland natural gas-based power generation. Natural gas prices have historically experienced more
volatility than coal, leading to a greater sense of uncertainty about future natural gas prices than
coal prices. Consequently, it would be fair to say that fuel price risk is greater for natural gas than
for coal, and much greater for both than for nuclear.
See Figures 13, 14, and 16 for historical natural gas, coal and nuclear fuel prices. Historical prices
for uranium are shown in Figure 15. Nuclear fuel is the end result of a complex process which
starts with uranium.
See Figure 17 and Figure 18 (or Table 27 and Table 28) for the overall sensitivity of LCOE to
fuel costs in Base Cases I and II. See Figure 27 and Figure 28 (or Table 37 and Table 38) for the
breakdown of LCOE when fuel costs are lower than what is assumed in Base Cases I and II. See
Figure 29 and Figure 30 (or Table 39 and Table 40) for the breakdown of LCOE when fuel costs
are higher than what is assumed in Base Cases I and II.
Section 3.3 Operational Lifetime and Capacity Factors Nuclear power plants are long-lived,
having the potential to operate 60 or more years, 20–30 years beyond the typical lifetime of a
coal or natural gas plant. From an LCOE point of view, this additional lifetime does not, however,
result in substantial savings on the cost of generating electricity from the plant: increasing the
lifetime of a nuclear power plant from 40 years to 60 years reduces the levelized cost of electricity
by about 4 percent. This fact, which may be surprising, arises because the benefits of producing 20
additional years’ worth occur 40 years into the future and so are rather small when discounted to
present-value terms (see below). A general rule is that additional lifetime becomes less important
1. EXECUTIVE SUMMARY
3
for the economics of the plant the longer the plant’s original lifetime, the higher the discount rate
applied to its cash flows, and the lower its capital intensity.
See Figure 19 and Figure 20 (or Table 29 and Table 30) for the overall sensitivity of plant LCOE
to the lifetime of the plants in Base Cases I and II.
Because of the high capital but low operational costs of nuclear power, it is important for a
nuclear power plant to consistently operate near capacity (i.e. to attain high capacity utilization),
especially in its early years of operation. Capacity utilization at (mature) nuclear power plants
has increased dramatically since the 1980s and currently sits at about 90 percent.
See Figure 21 and Figure 22 (or Table 31 and Table 32) for the overall sensitivity of plant LCOE
to the lifetime of the plants in Base Cases I and II.
Section 3.4 Taxes The analysis accounts for federal, state, and local tax liabilities and interactions
among them.
Section 3.5 The Discount Rate A high discount rate (opportunity cost of capital) disfavors power
generation projects with high front-end costs. Nuclear projects are therefore more vulnerable to
a higher cost of capital compared with coal and especially with natural gas. For example, we
find that increasing the discount rate from 8 percent to 12 percent increases the levelized cost of
nuclear power by 50 percent, the levelized cost of coal power by 30 percent, but the levelized cost
of natural gas power by only 10 percent. A high discount rate would also disfavor projects whose
revenues are loaded more toward the end of the project’s life; but with all scenarios considered
here, the plants operate and generate revenue uniformly throughout their operational lifetime.
See Figure 23 and Figure 24 (or Table 33 and Table 34) for the overall sensitivity of plant LCOE
to the discount rate applied to the cash flows of the plants in Base Cases I and II.
Section 3.6 Carbon Dioxide Emissions Any future public policies implying restrictions or financial
penalties on carbon dioxide emissions favor the economics of nuclear power by disfavoring natural gas and especially coal. The cost of nuclear power is completely insensitive to CO2 charges,
as CO2 is not a byproduct of nuclear power generation. Both coal and natural gas are vulnerable
to future carbon dioxide constraints. Due to the carbon intensity of coal as a fuel compared with
natural gas, standard coal plants are especially at such risk. In our base cases, a $30/ton charge
on carbon dioxide emissions increases the LCOE from coal by 46 percent and from gas by 20
percent.
See Figure 25 and Figure 26 (or Table 35 and Table 36) for the overall sensitivity of LCOE to
charges on CO2 emissions. See Figure 31 and Figure 32 (or Table 41 and Table 42) for the
breakdown of LCOE when a CO2 charge of $25 per ton is applied to the plants of Base Cases I
and II. See Figure 33 and Figure 34 (or Table 43 and Table 44) for the breakdown of LCOE when
a CO2 charge of $50 per ton is applied to the plants of Base Cases I and II.
Section 4 Levelized Costs for Combinations of Fuel and CO2 Emissions Prices Fuel prices
and the cost of CO2 emissions have independent impacts on the levelized cost of electricity, such
that the total impact is the sum of the impacts of each. For both the basic coal and natural gas
plants, the LCOE is reported for each combination of a wide range of CO2 and fuel prices.
Table 1 gives the cost of natural gas power for various combinations of natural gas prices and CO2
charges. Gas prices range between $2 and $20 per MMBTU, and CO2 charges range from $0 to
$100 per ton. For example, if over the lifetime of the project CO2 prices were $50/ton and natural
gas prices were $8/MMBTU, then the levelized cost of electricity from such a project would be
$101/MWh.
A REVIEW
4
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Table 1: Levelized costs ($/MWh) of gas-fired generation for given gas (column) and CO2 (row)
prices.
$0
$25
$50
$100
$2
$4
$6
$7
$8
$10
$12
$16
$20
24
34
44
63
43
53
63
82
62
72
82
101
72
82
91
111
81
91
101
120
91
101
110
130
110
120
129
149
148
158
167
187
186
196
205
225
In the absence of charges for CO2 , coal prices need to exceed an inflation-adjusted $5.00 per
MMBTU before coal becomes a more expensive option than nuclear power. With a $25/ton
charge on CO2 , however, coal becomes the more expensive option once coal prices exceed about
$2 per MMBTU (approximately the current price of coal). An important point to note here is that
the cost of coal increases more rapidly with increasing CO2 charges than does natural gas power,
owing to the lower CO2 emissions of natural gas plants on a per-unit-of-electricity-generated
basis. At $50 per ton of CO2 , coal-based power is more expensive than nuclear for any reasonable
price of coal.
Table 2 gives the cost of coal-based power for various combinations of coal prices and CO2
charges. Coal prices range between $1 and $7 per MMBTU, and CO2 ranges from $0 to $100
per ton. For example, if over the lifetime of the project CO2 prices were $50/ton and coal prices
were $2/MMBTU, then the levelized cost of electricity from such a project would be $105/MWh.
Table 2: Levelized costs ($/MWh) of coal-fired generation for given coal (column) and CO2
(row) prices.
$0
$25
$50
$100
$1
$2
$3
$4
$5
$6
$7
50
73
95
140
60
82
105
150
69
92
115
160
84
107
129
174
89
112
134
179
99
121
144
189
108
131
154
199
See Tables 7, 8, and 9 for the LCOE of the plants in Base Case I to combinations of fuel prices
and CO2 charges. See Tables 10, 11, 12, 13, and 14 for the LCOE of the plants in Base Case II to
combinations of fuel prices and CO2 charges.
Section 5 Levelized Costs with Uncertain Fuel Costs As noted above, coal and particularly
natural gas power plants are subject to considerable fuel price risk over their operating lifetime.
Previous sections of this report address the first aspect of fuel price risk; namely, the sensitivity of
LCOE to the price of fuel. Accounting for the second aspect requires that the uncertainty of fuel
prices is quantified so that an assessment can be made about how likely certain future fuel prices
are compared with others. The analysis of this section accomplishes this with a model of future
fuel prices. The model is calibrated to actual past coal and natural gas prices and yields possible
future fuel price paths and their associated likelihoods.
These simulations suggest that for natural gas plants, the probability is about 50 percent that
LCOE would fall somewhere between $45 and $75 per MWh; a 10 percent chance that LCOE will
exceed $99 per MWh; and a 10 percent chance that LCOE will be below $38 per MWh. The likely
future path of coal prices, based on the model and historical prices, is within a much narrower
2. SCENARIOS
5
band than that of natural gas. For coal, predicted future prices entail a 50 percent chance that
levelized costs will range between $56 and $62 per MWh; a 10 percent chance that levelized
costs will exceed $66 per MWh; and a 10 percent chance that levelized costs will be below $54
per MWh.
See Figure 1 and Figure 2 (or Table 15 and Table 16) for natural gas and coal price forecasts
under the model used in this study. See Figure 3 and Figure 4 for the range of plausible LCOEs
for the natural gas and coal plant in Base Case I when fuel prices vary according to the range of
forecasts produced by the model used in this study.
2. Scenarios
To calculate an estimate of the overall cost of electricity generated from a given technology, certain technical and financial characteristics of that technology need to be specified, as do the broader economic
conditions to which the operation would be subject. Economic conditions, including future inflation
rates and prices for coal and natural gas are based on EIA data. Details on the way these specifications
figure into the estimation of levelized costs are given in Section 3.
This study considers two sets of specifications, referred to as Specifications I and Specifications
II. Specifications I is drawn from a 2009 report by the Massachusetts Institute of Technology (MIT)
and are standard technologies for coal, natural gas, and nuclear power plants. A 2003 MIT report
(MIT 2003) discusses the technical details of these technologies. Specifications II is based on a 2010
report published by the U.S. Energy Information Administration (EIA). Along with standard coal and
natural gas technologies similar to those in Specifications I, Specifications II includes two technologies
with carbon-capture capability: one a standard natural gas combined cycle and the other an integrated
gasification combined cycle (IGCC) coal plant.
Although Specifications I draws significantly from the 2009 update (MIT 2009) to the 2003 study
The Future of Nuclear Power: An Interdisciplinary Study (MIT 2003), because the goal is to estimate costs
for plants located in Utah, we make several modifications to the specifications given in MIT 2009. First,
dollar amounts are adjusted for inflation. For example, in the case of a nuclear power plant, MIT 2009
gives $4,000 per KWh for construction cost (the sum of EPC and owner’s costs) in year 2007 dollars.
Expressed in year 2011 dollars this becomes $4,295 per KWh. Second, construction, incremental capital
costs, and both variable and fixed costs were inflated by 15 percent for the natural gas power plant as
an adjustment for lost efficiency due to elevations typical for locations in Utah. The adjustment factor
(15 percent) is drawn from PacifiCorp 2011. Applying the elevation adjustment factor, the construction
cost for the natural gas plant given in MIT 2009—$850 per KWh—becomes $1,008 per KWh in 2011
dollars.1
The IGCC plant and all the natural gas plants considered in this report use a “combined cycle”
technology. This means that the gas is burned in a gas turbine, then the heat in the exhaust stream is
used to produce steam to power a steam turbine. The use of what would otherwise be waste heat gives
combined cycle plants high thermal efficiency. A beneficial side-effect of high thermal efficiency is that
less fuel needs to be burned.
Upstream of the “gasification” part, IGCC plants are similar in concept to combined cycle natural
gas plants. But up to and including gasification, they are quite apart from both natural gas plants and
traditional coal plants. Whereas traditional coal-fired plants burn coal directly and remove unwanted
byproducts after complete combustion has taken place, IGCC plants generate electricity through burning a coal-derived gas (referred to as a synthesis gas, or “syngas”) after the byproduct-precursors are
removed. The gas is produced by placing coal in a pressurized vessel (the “gasifier”) with steam, but
without enough oxygen for complete combustion to take place. Under these conditions, the molecules
6
A REVIEW
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
in the coal break apart and undergo a series of chemical reactions to form hydrogen, carbon monoxide,
and other gaseous compounds. With IGCC, unwanted elements such as sulfur, mercury, and particulate
matter are then removed from the syngas and the carbon monoxide (a criteria pollutant) is converted
to carbon dioxide. Since the gas is still under pressure, pre-combustion cleaning with IGCC is more
efficient than the post-combustion cleaning of traditional plants. This ability to capture CO2 efficiently
is one of the main benefits of IGCC.
The cost estimates for the plants with carbon-capture capability include only equipment costs. That
covers only the “capture” part of carbon capture and sequestration. Much still needs to be resolved on
the “sequestration” side, including the issue of who owns the liability of the CO2 once it’s sequestered.
It is important to bear this in mind when comparing the estimates of the LCOE for IGCC and natural
gas combined cycle with carbon capture with that of the inherently CO2 -free nuclear power.
This report defines a scenario as a particular combination of power-generation technology, projectspecific costs such as construction costs, and broader costs such as fuel or the hurdle rate.
Below is a listing and brief description of the defining characteristics of the power plants analyzed
in this report, followed by Table 3 and Table 4, which indicate the values those characteristics have
under the two sets of Base Scenarios.
Construction The year construction on the power plant begins.
Operations The year operation of the completed power plant begins (first commercial production of
electricity). The time required to construct the plant is the difference between the year of initial
operation and the year of initial construction.
Lifetime The number of years the plant is assumed to be in commercial operation.
Nameplate The capacity for the plant to produce electricity, measured in megawatts (MW).
Capacity Factor A percent which indicates the utilized fraction of the plant’s maximum capacity to
produce electricity.
Heat Rate The amount of energy (measured in BTUs) in the fuel utilized by a power plant needed to
produce one unit of electricity (measured in kilowatt-hours (KWh)).
EPC Engineering, procurement, and construction costs. These are the costs associated with the purchase and installation of the plant’s power system.
Owner’s Cost Expenses ancillary to the power system including, for example, the cost of acquiring and
preparing a site for the power plant.
Incremental Annual capital expenditures subsequent to the initial expenditure.
Variable Non-fuel costs that vary with the amount of electricity generated.
Fixed Costs that do not vary with the amount of electricity generated.
Fuel Cost of fuel per million BTU (MMBTU) as of the initial year of operations.
Waste A fee imposed by the federal government on each unit of electricity generated by a nuclear
power plant. Such fees are intended to fund an eventual federal solution to the problem of
long-term nuclear waste.
Decommissioning Costs associated with decommissioning the nuclear power plant at the end of its
operational life. Operators contribute into a sinking fund to finance this end-of-life cost.
3. LEVELIZED COSTS
7
Depreciation Capital costs are generally subject to IRS depreciation rules. For coal plants, depreciation
takes place over a 20-year period while for natural gas and nuclear it takes place over a 15-year
period.
Table 3: Scenarios I base-case assumptions. All dollar amounts are in current (2011) dollars.
Parameter
Coal
Nuclear
Gas
Construction
Operations
Lifetime (years)
Nameplate (MW)
Capacity Factor (%)
Heat Rate (BTU/kWh)
EPC ($/kW)
Owner’s Costs ($/kW)
Incremental ($/kW/year)
Variable (mills/kW/year)
Fixed ($/kW/year)
Fuel ($/MMBTU)
Waste ($/MWh)
Decommissioning ($/KW)
Depreciation
2013
2017
40
1,300
85
8,870
2,059
412
29.00
3.84
26
1.92
—
—
20
2013
2018
40
2,200
90
10,400
3,579
716
43.00
0.45
61
0.72
1
342
15
2013
2015
40
540
85
6,800
840
168
12.35
0.51
16.1
5
—
—
15
Table 4: Base-case assumptions in Scenarios II. All dollar amounts are in current (2011) dollars.
Parameter
Coal
IGCC
Nuclear
Gas
NGCC
Construction
Operations
Lifetime (years)
Nameplate (MW)
Capacity Factor (%)
Heat Rate (BTU/kWh)
EPC ($/kW)
Owner’s Costs ($/kW)
Variable (mills/kW/year)
Fixed ($/kW/year)
Fuel ($/MMBTU)
Waste ($/MWh)
Decommissioning ($/KW)
Depreciation
2013
2017
40
1,300
85
8,800
2,452
441
4.32
30.2
1.92
—
—
20
2013
2017
40
520
85
10,700
4,539
908
8.18
70.5
1.92
—
—
20
2013
2018
40
2,200
90
10,400
4,455
981
2.08
90.4
0.72
1
432
15
2013
2015
40
540
85
7,050
953
191
4.01
16.85
5
—
—
15
2013
2015
40
340
85
7,526
2,009
402
7.53
35.41
5
—
—
15
3. Levelized Costs
The levelized cost of electricity (LCOE) is the price that must be charged on each unit of electricity sold
from a power plant in order to recoup exactly the cost of producing it, including a competitive return
8
A REVIEW
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
on investment. In order to compute a project’s LCOE its cash flows have to be estimated.
A cash flow is the difference between a project’s revenues and costs during a certain interval of
time. In this report, cash flows are based on 1-year intervals, with t referring to the end of year t. In
other words, the cash flow for year t, denoted CF t , is the sum of the differences between revenues (R t )
and costs (C t ) incurred between the end of the previous year (t − 1) and the end of year t. Revenues
and costs over the life of the power plant are estimated using the technical and financial specifications
discussed above. Such cash flows are then discounted by an estimate of the opportunity cost of capital
for the project (see 3.5). The sum of the discounted cash flows is the net present value (NPV) of the
project. If d is the discount factor, the NPV is:
NPV = dCF1 + d 2 CF2 + d 3 CF3 + · · · + d T CF T
= d R1 − C1 + d 2 R2 − C2 + d 3 R3 − C3 + · · · + d T R T − C T
(1)
(2)
where it is understood that both revenues and costs depend on the price of electricity P. Revenue
depends on P in that revenue equals the product of price and electricity sales. Cost depends on price
too because taxes are included among the costs and the project’s tax bill depends on its revenue.
In this formulation, all costs are known, as is the amount of electricity sold during each period
of the power plant’s life. If an amount received for each unit of electricity sold is specified, then the
NPV of the project can be computed. The standard rule is that if the NPV is positive then, because the
project’s opportunity cost of capital is accounted for, this project is worthwhile as an investment. On
the other hand, if the NPV is negative, then the funds that would have been invested can be better
invested elsewhere.
Consider a price P received on each unit of electricity sold such that the NPV for the project is
positive. It follows that there is some lesser price P ∗ for which NPV is still positive. In other words,
the project is viable if P is the going price but will also be viable if the going price is merely P ∗ . But
then what’s true of P is true of P ∗ : there is a price P ∗∗ , less than P ∗ , at which the project would still
be viable; that is, the NPV is still positive when the price of electricity is P ∗∗ . The LCOE is the answer
to the question: what is the lower-bound on the price of electricity that ensures viability? The LCOE is
therefore the price of electricity that results in a NPV of exactly zero.
For the projects analyzed in this report, all revenue is derived from sales of electricity. Further,
the sales occur uniformly over the operating lifetime of each plant. Almost all the costs of a power
plant occur in one of two stages: a construction period and an operations period.2 Some power technologies (e.g. natural gas power plants) incur much of their total cost during the operations phase
as purchases of natural gas. Other technologies (e.g. nuclear power plants) incur much of their cost
during construction. Costs, unlike revenues, can be quite lumpy for some of the projects of this report.
Subsequent sections of this report discuss further details on the components of the cash flows described above. However, before discussing such details it will be useful to briefly review the findings of
past work.
Three studies carried out since 2000 are particularly relevant to the present one. Two of these were
carried out by MIT (MIT 2003 and MIT 2009) and the other by the University of Chicago (UC 2004).
The methods employed by these studies are similar to each other and to those of the present study.
Table 5 lists the basic findings of the three studies.
It is important to bear in mind that the estimates shown in Table 5 reflect different sets of assumptions regarding such things as construction costs, fuel costs, and the developer’s discount rate. In
addition, the estimates are quoted in different years’ dollars. The estimates reported by the University
of Chicago study are given in year 2004 dollars, while those of the MIT studies are given in year 2002
and year 2007 dollars, respectively.
3. LEVELIZED COSTS
9
Table 5: Basic findings of three influential studies on the economics of nuclear power. Estimates are given in
nominal dollars per megawatt-hour of electricity generated.
Study
MIT 2003
UC 2004
MIT 2009
Coal
Natural Gas
Nuclear
42
33–41
62
38–56
35–45
65
42–67
47–71
84
The 2003 study by MIT (MIT 2003) estimates that the levelized cost of coal-based generation is
$42/MWh, compared with $38/MWh to $56/MWh for natural gas, and $42/MWh to $67/MWh for
nuclear. The range of estimates given for gas-based power reflects different assumptions concerning the
price of natural gas. For nuclear, the range reflects different assumptions regarding construction costs,
operations and maintenance costs, and the developer’s discount rate. Thus, in the scenarios considered
by MIT 2003, natural gas comes out between slightly less expensive than coal and the best-case nuclear
scenario and a point about equal with base-case nuclear.
A 2004 study carried out by the University of Chicago (UC 2004) also finds coal and natural
gas-based power less expensive than nuclear. The levelized cost of coal is given as a range between
$33/MWh and $41/MWh, compared with $35/MWh to $45/MWh for natural gas and between $47/MWh
and $71/MWh for nuclear. The worst-case cost of nuclear is approximately twice the cost of best-case
natural gas or coal. On the other hand, best-case nuclear is slightly more expensive than either worstcase natural gas or coal.
The most recent of these studies is a 2009 study by MIT (MIT 2009)—an update of the 2003
study—which gives estimated levelized costs of $62/MWh for coal, $65/MWh for gas, and $84/MWh
for nuclear.
3.1. Construction
Not only is nuclear power more sensitive to proportional changes in construction cost, but because
of the dearth of recent nuclear plant construction experience in the U.S. point-estimates of nuclear
power construction costs are subject to considerably more uncertainty than that of coal and gas-fired
plants. The lack of recent construction experience also implies that costs may decline significantly as
new nuclear power units are built (“learning by doing”). This reasoning also applies to advanced fossil
fuel and renewable energy competitors to nuclear power.
The construction cost of a power plant is based in part on the “overnight cost” of construction. This
is the cost of construction if such could be done overnight. The concept is useful because it gives a
measure of construction expenditures that is exclusive of the costs of financing those expenditures. The
overnight cost itself is the sum of engineering-procurement-construction (EPC) cost and the owner’s
cost. The EPC cost is that associated with the basic equipment and construction labor for the plant’s
power system, while owner’s costs include ancillary expenditures (e.g. cooling facilities, onsite buildings
and land).
Owner’s costs are often estimated as a fraction of EPC costs. The fraction usually runs between
10 and 20 percent, with 20 percent being more typical. An important factor in the size of owner’s
costs is the extent of prior development of the proposed plant site. Power units added to the site of a
pre-existing project (a “brownfield” site) are able to forego some of the costs that would be necessary
to develop a new site (a “greenfield” site).
The most significant difference between the 2003 and 2009 studies is the estimated construction
cost for nuclear power. In particular, the estimated overnight construction cost for nuclear power
10
A REVIEW
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
increased from $2,000 per KW reported in the 2003 study to $4,000 in the 2009 study. Why the large
increase? The study reports an estimated 15 percent annual increase in the cost of new construction
over the five-year period 2002 to 2007—the years on which the 2003 and 2009 studies are based. The
estimate of 15 percent is based on a combination of actual builds overseas and proposed builds in the
U.S.
Other recent sources seem to lend support to the $4,000/KW estimate given by the 2009 MIT
study. A recent article by the World Nuclear Association (WNA 2011) summarizes much of the public
information concerning estimates of the construction costs of nuclear power. First, it notes that as of
mid-2008 overnight engineering, procurement, and construction costs (EPC) for a nuclear reactor were
quoted at about $3,000/KW without owner’s costs. Generally, owner’s costs are estimated at about
20 percent of overnight costs, so that in this case the sum of EPC and owner’s cost comes to about
$3,600/KW. WNA 2011 refers to estimates by the U.S. Energy Information Agency (EIA 2010)—the
main source of technical and financial specifications for the Scenarios II of the present study—in which
the sum of EPC and owner’s cost is estimated as $5,339/KWh, up from the estimated $3,902/KWh in
the previous year.
Regarding overseas developments, the article notes that China reports expecting total construction
costs of between $1,600/KW and $2,000/KW. The article goes on to say that if the above estimates for
U.S. and China are correct, the implication is that the costs are about 3 times higher for the same plant
built in the U.S. versus China. As to the difference, they note that in addition to the differing labor
rates between the two countries, “Standardized design, numerous units being built, and increased
localisation are all significant factors in China.” In addition, they give two tables which show costs of
generation as estimated by the International Energy Agency (IEA). These tables show a great variety in
estimated costs by power source across different countries, with nuclear coming in less expensive than
other options in some cases and more expensive in others.
Lastly, the article turns to proposed developments in the U.S. It is stated that Florida Power and
Light recently reported $3,108/KW to $4,540/KW (EPC plus owner’s costs) as its estimate for two new
reactors at its Turkey Point site. Costs are also reported for other proposed developments, but in those
cases it is not clear of what exactly the costs consist (e.g. whether overnight costs are included and
whether net of financing costs).
Estimates for the cost of nuclear power have generally risen in recent years. Speaking to this issue,
a 2008 article (Kidd 2008) from Nuclear Engineering International states:
There is now a huge range of numbers in the public domain about the costs of new nuclear
build. It has become clear that estimates produced by vendors a few years ago of below
$2,000/kWe on an overnight basis (i.e. without interest costs) were wide of the mark, at
least for initial units in a market such as the USA. It is also clear that such estimates were
presented on a very narrow basis, ignoring important cost categories such as necessary
investment in local power grids, while costs have recently been spiraling upwards, owing
to a variety of important features. Recent public filings and announcements suggest that
there is now a ‘sticker shock’ in US new build, with cost estimates now commonly in the
$3,000–7,000/kWe installed range, depending on what is being included. Progress Energy’s
estimates for its new planned AP1000 units in Florida were particularly startling—a price
tag of $14 billion plus another $3 billion for necessary transmission upgrades.
Indeed, it would be fair to credit Moody’s Investors Service for being ‘ahead of the
game’ on assessing this, as in October 2007 they produced a report entitled New Nuclear Generation in the United States: Keeping Options Open vs Addressing An Inevitable
Necessity, which estimated the all-in costs of a nuclear plant to be between $5,000 and
3. LEVELIZED COSTS
11
$6,000/kWe. The report did however provide a note of caution, stating: “While we acknowledge that our estimate is only marginally better than a guess; it is a more conservative estimate than current market estimates.” Explaining the shortcomings of cost estimates
in more detail, the report stated: “All-in fact-based assessments require some basis for an
overnight capital cost estimate, and the shortcomings of simply asserting that capital costs
could be ‘significantly higher than $3,500/KWe’ should be supported by some analysis.”
The lower end of the estimates given by Florida Power and Light ($3,108) and the high given by
Moody’s ($6,000) bracket the two estimates of overnight costs used in the present study.
3.2. Fuel and Other Operations and Maintenance Costs
A variety of periodic costs are incurred once construction is complete and a project enters its operations
phase. These are usefully classified as fuel costs, variable costs, fixed costs, and incremental capital
costs. Fixed costs and incremental capital costs depend only on the plant’s generation capacity, while
fuel costs and variable costs depend only on the fraction of the plant’s capacity that is utilized. Compared with coal- and gas-based power, the cost of nuclear power is less sensitive to the cost of fuel. For
example, a doubling of the cost of nuclear fuel leads to an approximately 10 percent increase in the
total cost of nuclear power generation. Doubling the cost of coal and natural gas leads to increases of
approximately 32 and 77 percent, respectively, in the cost of coal- and natural gas-based power generation. Since natural gas power plants are particularly sensitive to natural gas prices and since natural
gas prices are particularly volatile, fuel price risk is considerably higher for natural gas plants than for
either coal or nuclear.
The attractiveness of nuclear power depends on the future course of coal and natural gas prices.
The cost of generating electricity from nuclear power is relatively insensitive to the cost of nuclear fuel
and particularly to the cost of uranium, the basic component of nuclear fuel.
We find that if current conditions (e.g. moderate natural gas and coal prices with no charge for
carbon dioxide emissions) typify those of the next 30–40 years, nuclear power would turn out to be
approximately 40 percent more expensive than either natural gas or coal on a per-unit-of-electricity
basis. There are, however, plausible combinations of future fossil-fuel prices and carbon dioxide (CO2 )
emissions charges under which nuclear power is significantly less expensive than that based on either
natural gas or coal.
Current delivered natural gas and coal prices per million BTU (MMBTU) are approximately $5.00
and $2.00 respectively. Higher natural gas and coal prices and/or charges based on CO2 emissions raise
the cost of generating electricity from these sources and so improve the relative economics of nuclear
power. We find that if inflation-adjusted natural gas prices are greater than about $7.50 per MMBTU
over the next 30–40 years, then natural gas power will be more expensive than nuclear even without
a charge on CO2 emissions. With a $25/ton charge on CO2 , such a “break-even-with-nuclear” point is
reached at $6.50 per MMBTU.
3.3. Operational Lifetime and Capacity Factors
Chief among the ongoing financial risks is the risk associated with the use of the plant’s capacity to
produce electricity. In the earlier years of nuclear power plants, the amount of electricity generated
out of the maximum that could be generated (the “capacity factor”) was quite low, averaging about 50
percent in the 1980s, for example. This started to change in the 1990s and for the last decade capacity
utilization at nuclear power plants has averaged about 90 percent. Such plants are rather mature, but
the age of a plant wouldn’t seem to work unambiguously in favor of higher capacity usage. Thus, there
12
A REVIEW
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
would seem to be reason to expect that new nuclear plants could enjoy such high capacity rates from
near the start of operation. It is critical that consistently high capacity usage is realized early in the
plant’s lifetime.
Nuclear power plants are potentially long-lived, with feasible lifetimes of 60+ years.3 From an
LCOE point of view, however, the lifetime of a nuclear plant is not especially critical as long as the plant
lives and operates near capacity for about 30 years. Figures 19 and Figures 20 shows the sensitivity of
LCOE to the plant’s operational lifetime. In these figures, note that the LCOE for natural gas (including
NGCC) actually increases slightly with increasing lifetime. This is a consequence of EIA-projected
increases in the real cost of natural gas. Adjusting for the effect of rising natural gas prices, the LCOE
for natural gas does decrease with increased lifetime, but only very slightly. In other words, if we ask:
how much would need to be charged for every unit of electricity sold in order that a natural gas plant
could be replaced in 20 years versus 40? The answer would be, perhaps surprisingly, just a few percent
of the price charged per unit for a 20-year unit. The answer is similar, but not quite as extreme for coal
and nuclear power. But as the figure shows, the additional current value added by a nuclear power
plant that lives 60 years versus one that lives 40 years is quite small ($88 per MWh for a 40-year plant,
$85 per MWh for a 60-year plant).
3.4. Taxes
The power plants analyzed in this report pay state and federal corporate taxes and local property taxes.
Local taxes (LT) are ordinarily assessed on the market value of an asset. In this report local taxes are
approximated by a levy equal to 0.95 percent (LR) of a measure of taxable income in which neither
state nor federal corporate income taxes are deductible. The state corporate income tax rate is a flat 5
percent (SR). The progressive federal corporate tax rates are approximated by a flat rate of 37 percent
(FR). Local taxes are deductible from both state and federal taxable income. State corporate income
taxes are deductible from federal taxable income. Thus the effective tax rate (ER) on taxable income is
calculated as
ER = LR + (1 − LR) × SR + 1 − LR − (1 − LR) × SR × FR,
(3)
which is equal to 40.7 percent.
State (SIT) and federal taxes (FIT) are based on taxable income, which starts as gross revenue
(REV) minus the sum of depreciation (DEP), fixed operations and maintenance expenses (FOM), nonfuel variable operations and maintenance expenses (VOM), incremental capital costs (INC), fuel costs
(FUEL), charges for nuclear fuel disposal (WAS), and contributions to the decommissioning fund (DEC).
LT = LR × (REV − DEP − FOM − VOM − INC − FUEL − WAS − DEC)
(4)
Local taxes are deductible from revenues when calculating taxable income for the purpose of computing
the Utah corporate income tax, but the federal corporate income tax is not.4 Therefore we compute
SIT as:
SIT = SR × (REV − LT − DEP − FOM − VOM − INC − FUEL − WAS − DEC) .
(5)
Taxable income for the purposes of the Federal Income Tax (FIT) is computed in the same way as for
SIT, except that SIT is a deduction in the calculation of federal taxable income. The Federal Income Tax
(FIT) is assumed to be a flat 38 percent charge against taxable income, which is gross revenue (REV)
minus the sum of depreciation (DEPR), incremental capital expenditures (CAPEX), non-fuel operations
and maintenance expenses (OM), fuel costs (FUEL), state corporate income taxes (SIT), and local taxes
(LOCAL). In the case of federal taxable income, both state and local taxes are deductible.
FIT = FIT rate × (REV − DEPR − CAPEX − OM − FUEL − SIT − LOCAL)
(6)
3. LEVELIZED COSTS
13
3.5. The Discount Rate
A power plant generates revenues and costs throughout its lifetime. Revenues are based on electricity
sales during the operational phase of the plant, while costs occur during both the construction and
operations phases. The difference between revenues and costs during some period of time is the plant’s
cash flow. Cash flows will be negative during the construction phase because in this phase there are
costs but no revenues. Cash flows would hopefully, but not necessarily, be positive during most or all
periods of the operations phase.
Because in order to assess the total value of a project we need to add together cash flows from
different points in the future, it is necessary that future cash flows be rendered in a common unit of
value. Customarily that unit is the present-value of the cash flow. Usually, though not necessarily, a
cash flow received “now” is more valuable to the investor than the same cash flow received at a later
date. This occurs when funds in hand now can be employed in activities that generate a sufficiently
positive financial return. Similarly, a negative cash flow is usually less costly to the investor the farther
into the future it occurs. In such typical cases, reexpression of future amounts in terms of their present
value is referred to as discounting and the rate of translation from one period to the next is called the
discount rate, which is denoted by r. Thus, an amount that occurs k periods in the future is rendered
in present-value terms through k successive applications of one-period discounting. In order to carry
these calculations out, a discount rate needs to be determined for each scenario.
Before investment in a particular project takes place, the investor will have numerous alternative
investments available. These investments will vary in apparent risk and expected reward (rate of
return). The rate of return on those alternatives with similar risk as the proposed investment establishes
a lower-bound on the rate of return for the proposed investment. This lower-bound rate of return is
called the hurdle rate. The hurdle rate is thus said to establish the opportunity cost of investing one’s
funds in the proposed project: If the rate of return on the proposed project is at least equal to the hurdle
rate, then the investor is doing as well or better to invest in the proposed project as in any alternative
with similar risk.
In practice, the hurdle rate for a project is often established by the weighted average cost of capital
(WACC). The WACC is a weighted average of the required rates of return to investors in the equity and
debt of the project, where the weights are the shares of equity and debt in total project value. Both the
shares and required rates depend on the risk-reward profile of the project. Generally, higher rates of
return and/or a greater equity share is required for higher-risk projects.
The components of WACC for the projects analyzed in this report are from the 2009 MIT Update
(MIT 2009), with minor modifications to account for a different assumption regarding inflation. The
required rate of return on equity for a nuclear power plant is assumed in MIT 2009 to be 15 percent
nominal, while both coal and natural gas plants are assumed in MIT 2009 to require rates of return
on equity of 12 percent nominal. These nominal rates incorporate a rate of inflation of 3 percent.
Adjusting the nominal rate for an up-to-date projection of the inflation rate of 1.8 percent, the nominal
rate of return on equity for a nuclear power plant is 13.66 percent, and 10.7 percent for both coal and
natural gas.5 For nuclear, coal, and gas, MIT 2009 assumes an 8 percent nominal rate of return to debt.
Again adjusting for different inflation assumptions, this study assumes a 6.74 percent nominal rate of
return to debt. Lastly, MIT 2009 assumes a 50-50 split between debt and equity for nuclear and a 60-40
split for both coal and natural gas. Using these components the WACC can be computed for each plant.
Letting se stand for equity share, (1 − se ) for debt share, re for required rate of return on equity, rd for
required pre-tax rate of return on debt, and t for tax rate, the WACC is calculated as follows:
WACC = se × re + 1 − se × rd × (1 − t) .
(7)
Since payments to debt are tax deductible, the after-tax cost per unit of debt is rd × (1 − t) where t
A REVIEW
14
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
is the marginal tax rate. This difference between the pre- and post-tax cost of debt is referred to as the
tax shield of debt. Table 6 summarizes the components and value of the WACC for each plant.
Table 6: Calculating the discount rates.
Nuclear
Gas
Coal
se
(1 − se )
re
rd
t
WACC
50%
40%
40%
50%
60%
60%
13.66%
10.70%
10.70%
6.74%
6.74%
6.74%
40.7%
40.7%
40.7%
7.86%
6.80%
6.80%
The sensitivity of the levelized cost of electricity to the discount rate depends on how the plant’s
cash flows are distributed over time. Projects front-loaded with larger negative cash flows, such as
nuclear power or advanced coal plants, are more susceptible to higher discount rates.
For example, we find that increasing the discount rate from 8 percent to 12 percent increases the
levelized cost of nuclear power by 50 percent, the levelized cost of coal power by 30 percent, but the
levelized cost of natural gas by only 10 percent. A high discount rate would also disfavor projects whose
revenues are loaded more toward the end of the project’s life; but with all scenarios considered here,
the plants operate and generate revenue uniformly throughout their operational lifetime. Figure 23
and Figure 24 show the levelized cost of electricity over a broad range of discount rates.
3.6. Carbon Dioxide Emissions
Carbon dioxide is a byproduct of the combustion of fossil-fuels in air. Assuming full combustion, each
atom of carbon from the fuel bonds with two atoms of oxygen from the air, yielding a number of CO2
molecules equal to the number of carbon atoms in the fuel. Burning one pound of coal or natural gas
creates more than one pound of CO2 . In order to determine the amount of CO2 emitted during some
period of time (e.g. a year) by a plant burning a certain fuel (and in the absence of carbon capture),
we determine
1. the amount of CO2 produced for each unit of fuel burned
2. the amount of fuel which must be burned to generate each unit of electricity, and
3. the total number of units of electricity generated by the plant during the period.
The amount of CO2 produced for each unit of fuel burned varies by fuel, as it depends on the share
of carbon in the weight of the fuel (the “carbon intensity” of the fuel). Even within broad categories
of fuel, such as “coal” and “natural gas,” carbon intensity varies. In this report, 1 MMBTU (equal to
85.5 lbs of 11,700 BTU/lb. coal) of coal is assumed to generate 204 lbs of CO2 .6 The carbon content
of natural gas is taken to be 76 percent by weight. With 1 standard cubic foot (SCF) of natural gas
energy-equivalent to 1,026 BTU and having a weight 0.042 pounds, it follows that 1 MMBTU of natural
gas generates 114 pounds of CO2 upon combustion.7
The amount of fuel, as measured by BTU, that must be burned to generate each KWh of electricity
is a measure of the thermal efficiency of the plant (called the plant’s “heat rate”). The coal plant
in Scenarios I, for example, requires 8,870 BTU of coal in order to generate 1 KWh of electricity;
equivalently, 8.87 MMBTU (758 lbs of 11,700 BTU/lb. coal) of coal are required to make 1 MWh. The
gas plant in Scenarios I requires 6.8 MMBTU to produce 1 MWh.8
The total amount of electricity generated by the plant during a given period is the product of the
capacity of the plant (“nameplate capacity”), the fraction of this capacity that is used during the period
4. LEVELIZED COSTS
FOR
COMBINATIONS
OF
FUEL
AND
CO2 EMISSIONS PRICES
15
(“capacity utilization rate”), and the number of hours during the period. For example, the coal plant
of Scenarios I has a nameplate capacity of 1,300 MW and a capacity utilization rate of 85 percent.
With an average 8,766 hours per year (accounting for leap years), this plant would generate 9,686,430
MWh per year. The natural gas plant of Scenarios I, with a nameplate capacity of 540 MW and capacity
utilization rate of 85 percent, would generate 4,023,594 MWh per year.
Putting these three factors together we compute CO2 emissions per year for each plant in each
scenario. For example, in Scenarios I the coal plant emits 8,763,701 tons of CO2 per year and the gas
plant emits 1,559,545 tons per year. With a $25 per ton charge on CO2 emissions, these plants would
face annual emissions charges of $219 million and $39 million respectively.
It bears repeating that the gas plant in this case generates less than half the amount of electricity
of the coal plant: scaling these amounts to the output of the plant, the coal plant emits almost 1 ton
of CO2 for each MWh of electricity generated, while the gas plant emits about 0.39 tons per MWh of
electricity generated.
The cost of nuclear power is completely insensitive to CO2 charges, as CO2 is not a byproduct
of nuclear power generation. Compared with coal- and gas-based power, the cost of nuclear power
is less sensitive to the cost of fuel. For example, a doubling of the cost of nuclear fuel leads to an
approximately 10 percent increase in the total cost of nuclear power generation. Doubling the cost of
coal and natural gas leads to increases of approximately 32 and 77 percent, respectively, in the cost
of coal- and natural gas-based power generation. Natural gas-based power plants in fact carry more
fuel-price risk than coal-based plants not because the overall cost of generation from gas is less sensitive
to natural gas prices than is the overall cost of generation from coal to coal prices—they are roughly
equally sensitive—but because the price of natural gas appears less certain than that of coal.
4. Levelized Costs for Combinations of Fuel and CO2 Emissions Prices
This section presents the LCOE for each of the eight base scenarios (three in Scenarios I and five in
Scenarios II) when evaluated simultaneously over a range of fuel and CO2 emissions prices. In each
table, the rows correspond to CO2 emissions prices and the columns correspond to fuel prices.
Table 7 shows, for the natural gas plant in Scenarios I, its LCOE for each combination of natural
gas prices between $2 and $20 per MMBTU and each CO2 emissions charge between $0 and $120.
For example, if natural gas costs $3/MMBTU and there are no CO2 emissions, the LCOE is $43/MWh.
But if natural gas costs $8/MMBTU and there is a $25/ton charge for CO2 emissions, then LCOE is
$101/MWh.
The other seven tables are read in the same way. One thing to note is that the IGCC and NGCC
plants in Scenarios II are equipped with, and assumed to utilize, carbon capture and sequestration
capability. The capture of carbon dioxide is not complete, however; only 90 percent of the carbon
dioxide is captured in both plants. That is why they, unlike the nuclear plants in both scenarios, are not
completely insensitive to a CO2 charge.
A REVIEW
16
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$60
$80
$100
$120
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
$2
$3
$4
$5
$6
$7
$8
$10
$12
$14
$16
$18
$20
$22
34
36
38
40
42
44
46
47
49
51
53
57
65
73
80
43
45
47
49
51
53
55
57
59
61
63
67
74
82
90
53
55
57
59
61
63
65
67
68
70
72
76
84
92
99
62
64
66
68
70
72
74
76
78
80
82
86
93
101
109
72
74
76
78
80
82
84
86
87
89
91
95
103
111
118
81
83
85
87
89
91
93
95
97
99
101
105
112
120
128
91
93
95
97
99
101
103
105
106
108
110
114
122
130
137
110
112
114
116
118
120
122
124
125
127
129
133
141
149
156
129
131
133
135
137
139
141
143
144
146
148
152
160
168
175
148
150
152
154
156
158
160
162
163
165
167
171
179
187
194
167
169
171
173
175
177
179
181
182
184
186
190
198
206
213
186
188
190
192
194
196
198
200
201
203
205
209
217
225
232
205
207
209
211
213
215
217
219
220
222
224
228
236
244
251
224
226
228
230
232
234
236
238
239
241
243
247
255
263
270
Table 7: Scenarios I: Levelized cost of gas-fired generation over various combinations of natural gas (columns)
and CO2 (rows) prices.
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$60
$80
$100
$120
$1
$1.5
$2
$2.5
$3
$3.5
$4
$4.5
$5
$5.5
$6
$6.5
$7
50
54
59
63
68
72
77
82
86
91
95
104
122
140
158
55
59
64
68
73
77
82
86
91
95
100
109
127
145
163
60
64
69
73
78
82
87
91
96
100
105
114
132
150
168
65
69
74
78
83
87
92
96
101
105
110
119
137
155
173
69
74
78
83
87
92
97
101
106
110
115
124
142
160
178
74
79
83
88
92
97
101
106
110
115
119
128
147
165
183
79
84
88
93
97
102
106
111
115
120
124
133
151
169
188
84
89
93
98
102
107
111
116
120
125
129
138
156
174
192
89
93
98
102
107
112
116
121
125
130
134
143
161
179
197
94
98
103
107
112
116
121
125
130
134
139
148
166
184
202
99
103
108
112
117
121
126
130
135
139
144
153
171
189
207
104
108
113
117
122
126
131
135
140
144
149
158
176
194
212
108
113
117
122
127
131
136
140
145
149
154
163
181
199
217
Table 8: Scenarios I: Levelized cost of coal-fired generation over various combinations of coal (columns) and
CO2 (rows) prices.
4. LEVELIZED COSTS
FOR
COMBINATIONS
OF
FUEL
AND
CO2 EMISSIONS PRICES
17
$0.25
$0.5
$0.75
$1
$1.25
$1.5
$1.75
$2
$2.25
$2.5
$2.75
83
83
83
83
83
83
83
83
83
83
83
83
83
83
83
86
86
86
86
86
86
86
86
86
86
86
86
86
86
86
89
89
89
89
89
89
89
89
89
89
89
89
89
89
89
92
92
92
92
92
92
92
92
92
92
92
92
92
92
92
94
94
94
94
94
94
94
94
94
94
94
94
94
94
94
97
97
97
97
97
97
97
97
97
97
97
97
97
97
97
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
103
103
103
103
103
103
103
103
103
103
103
103
103
103
103
106
106
106
106
106
106
106
106
106
106
106
106
106
106
106
109
109
109
109
109
109
109
109
109
109
109
109
109
109
109
112
112
112
112
112
112
112
112
112
112
112
112
112
112
112
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$60
$80
$100
$120
Table 9: Scenarios I: Levelized cost of nuclear generation over various combinations of nuclear fuel (columns)
and CO2 (rows) prices.
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$60
$80
$100
$120
$2
$3
$4
$5
$6
$7
$8
$10
$12
$14
$16
$18
$20
$22
39
41
43
45
47
49
51
53
55
57
59
63
71
79
87
49
51
53
55
57
59
61
63
65
67
69
73
81
89
97
59
61
63
65
67
69
71
73
75
77
79
83
91
99
107
68
70
72
74
76
78
80
82
84
86
88
92
101
109
117
78
80
82
84
86
88
90
92
94
96
98
102
110
118
126
88
90
92
94
96
98
100
102
104
106
108
112
120
128
136
98
100
102
104
106
108
110
112
114
116
118
122
130
138
146
118
120
122
124
126
128
130
132
134
136
138
142
150
158
166
137
139
141
143
145
147
149
151
153
155
157
161
169
178
186
157
159
161
163
165
167
169
171
173
175
177
181
189
197
205
177
179
181
183
185
187
189
191
193
195
197
201
209
217
225
196
198
200
202
204
206
208
211
213
215
217
221
229
237
245
216
218
220
222
224
226
228
230
232
234
236
240
248
256
264
236
238
240
242
244
246
248
250
252
254
256
260
268
276
284
Table 10: Scenarios II: Levelized cost of gas-fired generation over various combinations of natural gas (columns)
and CO2 (rows) prices.
A REVIEW
18
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$60
$80
$100
$120
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
$1
$1.5
$2
$2.5
$3
$3.5
$4
$4.5
$5
$5.5
$6
$6.5
$7
52
56
61
65
70
74
79
83
88
92
97
106
124
142
159
57
61
66
70
75
79
84
88
93
97
102
111
128
146
164
62
66
71
75
80
84
89
93
97
102
106
115
133
151
169
66
71
75
80
84
89
93
98
102
107
111
120
138
156
174
71
76
80
85
89
94
98
103
107
112
116
125
143
161
179
76
81
85
90
94
99
103
108
112
116
121
130
148
166
184
81
85
90
94
99
103
108
112
117
121
126
135
153
171
188
86
90
95
99
104
108
113
117
122
126
131
140
157
175
193
91
95
100
104
109
113
118
122
126
131
135
144
162
180
198
96
100
104
109
113
118
122
127
131
136
140
149
167
185
203
100
105
109
114
118
123
127
132
136
141
145
154
172
190
208
105
110
114
119
123
128
132
137
141
145
150
159
177
195
213
110
115
119
123
128
132
137
141
146
150
155
164
182
200
218
Table 11: Scenarios II: Levelized cost of coal-fired generation over various combinations of coal (columns) and
CO2 (rows) prices.
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$60
$80
$100
$120
$1
$1.5
$2
$2.5
$3
$3.5
$4
$4.5
$5
$5.5
$6
$6.5
$7
94
94
95
95
96
96
97
98
98
99
99
100
102
105
107
100
100
101
101
102
102
103
103
104
105
105
106
108
111
113
106
106
107
107
108
108
109
109
110
110
111
112
114
116
119
111
112
112
113
114
114
115
115
116
116
117
118
120
122
124
117
118
118
119
119
120
121
121
122
122
123
124
126
128
130
123
124
124
125
125
126
126
127
128
128
129
130
132
134
136
129
130
130
131
131
132
132
133
133
134
134
136
138
140
142
135
135
136
137
137
138
138
139
139
140
140
141
144
146
148
141
141
142
142
143
144
144
145
145
146
146
147
150
152
154
147
147
148
148
149
149
150
151
151
152
152
153
155
158
160
153
153
154
154
155
155
156
156
157
157
158
159
161
163
166
158
159
160
160
161
161
162
162
163
163
164
165
167
169
172
164
165
165
166
167
167
168
168
169
169
170
171
173
175
177
Table 12: Scenarios II: Levelized cost of IGCC (with 90 percent carbon capture and sequestration) generation
over various combinations of coal (columns) and CO2 (rows) prices.
5. LEVELIZED COSTS
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$60
$80
$100
$120
WITH
UNCERTAIN FUEL COSTS
19
$2
$3
$4
$5
$6
$7
$8
$10
$12
$14
$16
$18
$20
$22
60
60
61
61
61
61
61
62
62
62
62
63
64
64
65
71
71
71
71
72
72
72
72
72
73
73
73
74
75
76
81
81
82
82
82
82
82
83
83
83
83
84
85
85
86
92
92
92
92
93
93
93
93
93
94
94
94
95
96
97
102
102
103
103
103
103
104
104
104
104
104
105
106
107
107
113
113
113
113
114
114
114
114
114
115
115
115
116
117
118
123
123
124
124
124
124
125
125
125
125
125
126
127
128
128
144
145
145
145
145
145
146
146
146
146
146
147
148
149
149
165
166
166
166
166
166
167
167
167
167
167
168
169
170
170
186
187
187
187
187
187
188
188
188
188
189
189
190
191
192
207
208
208
208
208
208
209
209
209
209
210
210
211
212
213
228
229
229
229
229
229
230
230
230
230
231
231
232
233
234
249
250
250
250
250
251
251
251
251
251
252
252
253
254
255
270
271
271
271
271
272
272
272
272
272
273
273
274
275
276
Table 13: Scenarios II: Levelized cost of NGCC (with 90 percent carbon capture and sequestration) generation
over various combinations of natural gas (columns) and CO2 (rows) prices.
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$60
$80
$100
$120
$0.25
$0.5
$0.75
$1
$1.25
$1.5
$1.75
$2
$2.25
$2.5
$2.75
101
101
101
101
101
101
101
101
101
101
101
101
101
101
101
104
104
104
104
104
104
104
104
104
104
104
104
104
104
104
107
107
107
107
107
107
107
107
107
107
107
107
107
107
107
110
110
110
110
110
110
110
110
110
110
110
110
110
110
110
113
113
113
113
113
113
113
113
113
113
113
113
113
113
113
116
116
116
116
116
116
116
116
116
116
116
116
116
116
116
118
118
118
118
118
118
118
118
118
118
118
118
118
118
118
121
121
121
121
121
121
121
121
121
121
121
121
121
121
121
124
124
124
124
124
124
124
124
124
124
124
124
124
124
124
127
127
127
127
127
127
127
127
127
127
127
127
127
127
127
130
130
130
130
130
130
130
130
130
130
130
130
130
130
130
Table 14: Scenarios II: Levelized cost of nuclear generation over various combinations of nuclear fuel (columns)
and CO2 (rows) prices.
5. Levelized Costs with Uncertain Fuel Costs
As noted in previous sections, the cost of generating electricity from coal and natural gas—and therefore
the relative financial advantage or disadvantage of nuclear power—depends greatly on the future paths
of coal and natural gas prices.
20
A REVIEW
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Previous sections of this report presented estimates of the levelized cost of electricity for fixed
prices, or prices that change at a known and constant rate. In the base cases, for example, the inflationadjusted future price of natural gas is assumed to start at $5.00 and then increase at an annual rate of
1.5 percent per year.
An alternative approach, which conveys some of the uncertainty in projections of future fuel prices,
is to use models of future fuel prices which are calibrated to historical price data. A large number
of simulated future price paths are able to be generated from the model. Each simulated path is fed
into the model of levelized costs, which calculates the levelized cost of electricity for that price path.
The result is a large collection of levelized costs—one for each simulated price path—that mirror the
uncertainty of fuel prices. A Technical discussion of the model is in the subsequent section.
Figure 1 and Figure 2 show features of modelled future gas and coal prices. Each simulated fuel
price path fed into the model yields an LCOE. The variation among price paths is transmitted to the
LCOE.
Figure 3 and Figure 4 show a histogram of LCOE based on running the coal and gas price simulations
with the natural gas and coal power plants of Scenarios I. The main features of the histograms are
presented in Table 17 and Table 18. For the natural gas plant of Scenarios I, Table 17 shows, for
example, that there is approximately a 50% chance that levelized costs will range between $45.2 and
$74.7 per MWh; a 10 percent chance that levelized costs will exceed $98.9 per MWh; and a 10 percent
chance that levelized costs will be below $38.4 per MWh. For the coal plant of Scenarios I, Table 18
shows, for example, that there is approximately a 50% chance that levelized costs will range between
$55.8 and $62.2 per MWh; a 10 percent chance that levelized costs will exceed $66 per MWh; and a
10 percent chance that levelized costs will be below $53.7 per MWh. That is, given the assumptions in
the model, the likely LCOE of coal power fits within a much narrower band than does that of natural
gas power.
Although the model used here conveys some of the intuition one might have about uncertain future fuel prices, it must be noted that there are competing models and that there is controversy over
which models are most appropriate in certain circumstances. For example, the GBM models percentage
change in prices taking one independent step at a time. In the GBM model, price has no tendency, either
in the short or long run. It is thus said to describe a “mean-averting” process. This may be appropriate
in some settings, but in the case of resources like natural gas and coal it raises some concern. Most
importantly, mean-averting behavior seems to controvert the forces of supply and demand. As natural
gas (or coal) prices rise, the incentive increases for would-be producers to put more natural gas on the
market. At the same time, the incentive increases for users of natural gas to cut back. Taken together,
these dampening effects should mean prices revert to some sort of underlying average (maybe constant,
maybe shifting). Such an average, however, is not part of the GBM model. It is outside the scope of this
study to undertake an analysis of the plausibility of the many competing probability models for prices
and their effect on the value or LCOE of the power plant. We therefore present these simulation results
based on the GBM model with this note of caution.
5. LEVELIZED COSTS
WITH
UNCERTAIN FUEL COSTS
21
Simulated Natural Gas Prices
40
Upper/Lower 80 percent
Mean
Median
Simulated Paths
constant 2011 dollars per MMBTU
35
30
25
20
15
10
5
0
2012
2018
2024
2030
2036
2042
2048
2054
year
Figure 1: Forecast gas prices, under the assumption that gas prices follow a geometric Brownian motion. The
outermost lines represent the bounds of the 80 percent confidence intervals.
A REVIEW
22
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Table 15: Tabular representation of Figure 1: Simulated Natural Gas Prices.
Upper
Lower
Mean
Median
2012
2016
2020
2024
2028
2032
2036
2040
2044
2048
2052
5.0
5.0
5.0
5.0
6.3
4.5
5.7
5.3
7.5
4.1
6.3
5.6
9.0
3.8
6.9
5.9
10.8
3.5
7.7
6.1
12.9
3.2
8.5
6.5
15.5
3.0
9.4
6.8
18.6
2.7
10.3
7.1
22.2
2.5
11.4
7.5
26.6
2.3
12.6
7.8
31.9
2.1
14.0
8.2
5. LEVELIZED COSTS
WITH
UNCERTAIN FUEL COSTS
23
Simulated Coal Prices
5.0
Upper/Lower 80 percent
Mean
Median
Simulated Paths
constant 2011 dollars per MMBTU
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
2012
2018
2024
2030
2036
2042
2048
2054
year
Figure 2: Forecast coal prices, under the assumption that coal prices follow a geometric Brownian motion. The
outermost lines represent the bounds of the 80 percent confidence intervals.
Table 16: Tabular representation of Figure 2: Simulated Coal Prices.
Upper
Lower
Mean
Median
2012
2016
2020
2024
2028
2032
2036
2040
2044
2048
2052
2.0
2.0
2.0
2.0
2.1
1.9
2.1
2.0
2.3
1.9
2.1
2.1
2.4
1.8
2.2
2.1
2.5
1.8
2.3
2.1
2.7
1.7
2.3
2.1
2.8
1.7
2.4
2.2
3.0
1.6
2.5
2.2
3.1
1.6
2.6
2.2
3.3
1.6
2.6
2.3
3.5
1.5
2.7
2.3
A REVIEW
24
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
0.010
0.000
0.005
density
0.015
0.020
Histogram of Levelized Costs for Gas-Fired Generation
0
50
100
150
200
250
dollars per MWh
Figure 3: Histogram of levelized costs ($/MWh) of gas-fired generation. The histogram is the result of applying
the discounted cash flow model to the simulated prices depicted in Figure 1.
Table 17: Percentiles of levelized costs for gas-fired generation, provided that gas prices are well-represented as
a geometric Brownian motion having the parameters given in Table 45.
1%
10%
25%
50%
75%
90%
99%
$30.9
$38.4
$45.2
$57.0
$74.7
$98.9
$169.1
5. LEVELIZED COSTS
WITH
UNCERTAIN FUEL COSTS
25
0.04
0.00
0.02
density
0.06
0.08
Histogram of Levelized Costs for Coal-Fired Generation
0
20
40
60
80
100
dollars per MWh
Figure 4: Histogram of levelized costs ($/MWh) of coal-fired generation. The histogram is the result of applying
the discounted cash flow model to the simulated prices depicted in Figure 2.
Table 18: Percentiles of levelized costs for coal-fired generation, provided that coal prices are well-represented
as a geometric Brownian motion having the parameters given in Table 45. This table indicates, for example, that
there is approximately a 50% chance that levelized costs will range between $56.4 and $63.0 per MWh; a 10
percent chance that levelized costs will exceed $67.0 per MWh; and a 10 percent chance that levelized costs will
be below $54.2 per MWh.
1%
10%
25%
50%
75%
90%
99%
$51.1
$53.7
$55.8
$58.9
$62.2
$66.0
$73.8
A REVIEW
26
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
6. Breakdown of LCOE for Variations on Base Cases
62.48
58.92
20
40
60
80
88.29
0
dollars per MWh
100
120
140
Scenarios I: Base Case
Coal
Gas
Nuclear
Figure 5: Levelized costs ($MWh) in the Scenarios I base case.
Coal
Gas
Nuclear
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
27.00
3.89
4.88
4.40
18.75
0.00
0.00
0.00
9.95
1.66
0.63
2.69
47.55
0.00
0.00
0.00
63.24
5.45
0.57
9.70
8.38
0.73
0.00
0.22
Total
58.92
62.48
88.29
Table 19: Levelized costs ($MWh) in the Scenarios I base case.
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
27
120
140
Scenarios II: Base Case
106.43
91.76
80
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
60.88
20
40
60
68.42
0
dollars per MWh
100
104.59
Coal
IGCC
Gas
NGCC
Nuclear
Figure 6: Levelized costs ($MWh) in the Scenarios II base case.
Coal
IGCC
Gas
NGCC
Nuclear
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
31.61
5.51
5.16
18.61
0.00
0.00
0.00
59.51
10.41
12.04
22.62
0.00
0.00
0.00
11.30
5.00
2.82
49.30
0.00
0.00
0.00
23.81
9.39
5.93
52.63
0.00
0.00
0.00
80.02
2.62
14.40
8.38
0.73
0.00
0.28
Total
60.88
104.59
68.42
91.76
106.43
Table 20: Levelized costs ($MWh) in the Scenarios II base case.
A REVIEW
28
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Scenarios I: Sensitivity of Levelized Cost to Construction Cost
140
Coal
Gas
Nuclear
120
dollars per MWh
100
80
60
40
20
0
-50
-40
-30
-20
-10
0
10
20
percent deviation from base assumption
30
40
50
Figure 7: Scenarios I: Levelized costs (in year 2011 dollars) evaluated at overnight costs that are greater or lesser
than Scenarios I base-case overnight costs by the percentage indicated on the horizontal axis. The dark vertical
line corresponds to the overnight costs in the base case.
Coal
Gas
Nuclear
-50%
-40%
-30%
-20%
-10%
0%
10%
20%
30%
40%
50%
45
58
57
48
58
63
51
59
69
54
60
76
56
61
82
59
62
88
62
63
95
64
64
101
67
65
107
70
66
114
72
67
120
Table 21: Scenarios I: Levelized costs (in year 2011 dollars) evaluated at overnight costs that are greater or
lesser than Scenarios I base-case overnight costs by the indicated percentage.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
29
Scenarios II: Sensitivity of Levelized Cost to Construction Cost
160
Coal
IGCC
Gas
NGCC
Nuclear
140
dollars per MWh
120
100
80
60
40
20
0
-50
-40
-30
-20
-10
0
10
20
percent deviation from base assumption
30
40
50
Figure 8: Scenarios II: Levelized costs (in year 2011 dollars) evaluated at overnight costs that are greater or
lesser than Scenarios II base-case overnight costs by the percentage indicated on the horizontal axis. The dark
vertical line corresponds to the overnight costs in the base case.
Coal
IGCC
Gas
NGCC
Nuclear
-50%
-40%
-30%
-20%
-10%
0%
10%
20%
30%
40%
50%
45
75
63
80
66
48
81
64
82
74
51
87
65
85
82
55
93
66
87
90
58
99
67
89
98
61
105
68
92
106
64
111
70
94
114
67
116
71
97
122
70
122
72
99
131
74
128
73
101
139
77
134
74
104
147
Table 22: Scenarios II: Levelized costs (in year 2011 dollars) evaluated at overnight costs that are greater or
lesser than Scenarios II base-case overnight costs by the indicated percentage.
A REVIEW
30
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
80
75.6
60.49
53.52
20
40
60
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
0
dollars per MWh
100
120
140
Scenarios I: Low Construction Cost Case
Coal
Gas
Nuclear
Figure 9: Levelized costs ($/MWh) in the Scenarios I low overnight case.
Coal
Gas
Nuclear
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
21.60
3.89
4.88
4.40
18.75
0.00
0.00
0.00
7.96
1.66
0.63
2.69
47.55
0.00
0.00
0.00
50.59
5.45
0.57
9.70
8.38
0.73
0.00
0.18
Total
53.52
60.49
75.60
Table 23: Levelized costs ($/MWh) in the Scenarios I low overnight case.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
31
92.69
90.37
80
87
54.56
20
40
60
66.16
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
0
dollars per MWh
100
120
140
Scenarios II: Low Construction Cost Case
Coal
IGCC
Gas
NGCC
Nuclear
Figure 10: Levelized costs ($/MWh) in the Scenarios II low overnight case.
Coal
IGCC
Gas
NGCC
Nuclear
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
25.29
5.51
5.16
18.61
0.00
0.00
0.00
47.61
10.41
12.04
22.62
0.00
0.00
0.00
9.04
5.00
2.82
49.30
0.00
0.00
0.00
19.05
9.39
5.93
52.63
0.00
0.00
0.00
64.01
2.62
14.40
8.38
0.73
0.00
0.23
Total
54.56
92.69
66.16
87.00
90.37
Table 24: Levelized costs ($/MWh) in the Scenarios II low overnight case.
A REVIEW
32
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
120
140
Scenarios I: High Construction Cost Case
80
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
64.47
Coal
Gas
20
40
60
64.32
0
dollars per MWh
100
100.98
Nuclear
Figure 11: Levelized costs ($/MWh) in the Scenarios I high overnight case.
Coal
Gas
Nuclear
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
32.40
3.89
4.88
4.40
18.75
0.00
0.00
0.00
11.94
1.66
0.63
2.69
47.55
0.00
0.00
0.00
75.89
5.45
0.57
9.70
8.38
0.73
0.00
0.27
Total
64.32
64.47
100.98
Table 25: Levelized costs ($/MWh) in the Scenarios I high overnight case.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
33
140
Scenarios II: High Construction Cost Case
120
122.49
96.52
80
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
70.68
20
40
60
67.2
0
dollars per MWh
100
116.49
Coal
IGCC
Gas
NGCC
Nuclear
Figure 12: Levelized costs ($/MWh) in the Scenarios II high overnight case.
Coal
IGCC
Gas
NGCC
Nuclear
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
37.94
5.51
5.16
18.61
0.00
0.00
0.00
71.42
10.41
12.04
22.62
0.00
0.00
0.00
13.56
5.00
2.82
49.30
0.00
0.00
0.00
28.58
9.39
5.93
52.63
0.00
0.00
0.00
96.02
2.62
14.40
8.38
0.73
0.00
0.34
Total
67.20
116.49
70.68
96.52
122.49
Table 26: Levelized costs ($/MWh) in the Scenarios II high overnight case.
A REVIEW
34
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Historic Natural Gas Prices
constant 2011 dollars per MMBTU
10
9
8
7
6
5
4
3
2
1
0
1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010
year
Figure 13: Inflation-adjusted historic FOB prices per MMBTU of natural gas, 1950–2011.
Data Source: Energy Information Administration.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
35
Historic Coal Prices
constant 2011 dollars per MMBTU
10
9
8
7
6
5
4
3
2
1
0
1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010
year
Figure 14: Inflation-adjusted historic prices per MMBTU of bituminous coal, 1950–2010.
Data Source: Energy Information Administration.
Historic Uranium Prices
50
constant 2011 dollars per lb
45
40
35
30
25
20
15
10
5
0
1995
1997
1999
2001
2003
year
2005
Figure 15: Inflation-adjusted historic prices per pound of uranium, 1995–2010.
Data Source: Energy Information Administration.
2007
2009
A REVIEW
36
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Historic Fuel Costs for Electric Power Generation
constant 2011 dollars per MWh
90
Nuclear
Gas
Coal
80
70
60
50
40
30
20
10
0
1996
1998
2000
2002
2004
year
2006
2008
Figure 16: Inflation-adjusted historic fuel prices, 1996–2011.
Data Source: Nuclear Energy Institute.
2010
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
37
Scenarios I: Sensitivity of Levelized Cost to Fuel Cost
160
Coal
Gas
Nuclear
140
dollars per MWh
120
100
80
60
40
20
0
-60
-30
0
30
60
90
120
percent deviation from base assumption
150
180
Figure 17: Scenarios I: Levelized costs (in year 2011 dollars) evaluated at fuel costs that are greater or lesser
than Scenarios I base-case fuel costs by the percentage indicated on the horizontal axis. The dark vertical line
corresponds to the fuel costs in the base case.
Coal
Gas
Nuclear
-60%
-30%
0%
30%
60%
90%
120%
150%
180%
48
34
83
53
48
86
59
62
88
65
77
91
70
91
93
76
105
96
81
120
98
87
134
101
93
148
103
Table 27: Scenarios I: Levelized costs (in year 2011 dollars) evaluated at fuel costs that are greater or lesser than
Scenarios I base-case fuel costs by the indicated percentage.
A REVIEW
38
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Scenarios II: Sensitivity of Levelized Cost to Fuel Cost
200
Coal
IGCC
Gas
NGCC
Nuclear
180
160
dollars per MWh
140
120
100
80
60
40
20
0
-60
-30
0
30
60
90
120
percent deviation from base assumption
150
180
Figure 18: Scenarios II: Levelized costs (in year 2011 dollars) evaluated at fuel costs that are greater or lesser
than Scenarios I base-case fuel costs by the percentage indicated on the horizontal axis. The dark vertical line
corresponds to the fuel costs in the base case.
Coal
IGCC
Gas
NGCC
Nuclear
-60%
-30%
0%
30%
60%
90%
120%
150%
180%
50
91
39
60
101
55
98
54
76
104
61
105
68
92
106
66
111
83
108
109
72
118
98
123
111
78
125
113
139
114
83
132
128
155
116
89
139
142
171
119
94
145
157
186
122
Table 28: Scenarios II: Levelized costs (in year 2011 dollars) evaluated at fuel costs that are greater or lesser
than Scenarios I base-case fuel costs by the indicated percentage.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
39
Scenarios I: Sensitivity of Levelized Cost to Operational Lifetime
120
Coal
Gas
Nuclear
dollars per MWh
100
80
60
40
20
0
0
5
10
15
20
25
30
35
40 45
years
50
55
60
65
70
75
80
Figure 19: Scenarios I: Levelized costs (in year 2011 dollars) versus the operational lifetime of the power plant.
The dark vertical line corresponds to the lifetimes in the Scenarios I base case (40 years).
Coal
Gas
Nuclear
20
25
30
35
40
45
50
55
60
65
70
75
80
69
62
105
64
62
98
62
62
93
60
62
90
59
62
88
58
63
87
58
64
86
57
64
86
57
65
85
57
65
85
57
66
85
56
66
84
56
67
84
Table 29: Scenarios I: Levelized costs (in year 2011 dollars) versus the operational lifetime of the power plant.
A REVIEW
40
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Scenarios II: Sensitivity of Levelized Cost to Operational Lifetime
140
Coal
IGCC
Gas
NGCC
Nuclear
120
dollars per MWh
100
80
60
40
20
0
0
5
10
15
20
25
30
35
40 45
years
50
55
60
65
70
75
80
Figure 20: Scenarios II: Levelized costs (in year 2011 dollars) versus the operational lifetime of the power plant.
The dark vertical line corresponds to the lifetimes in the Scenarios I base case (40 years).
Coal
IGCC
Gas
NGCC
Nuclear
20
25
30
35
40
45
50
55
60
65
70
75
80
72
126
68
96
128
67
117
67
93
118
64
111
68
92
112
62
107
68
92
109
61
105
68
92
106
60
103
69
92
105
59
101
70
92
104
59
101
70
93
103
58
100
71
93
102
58
99
71
94
102
58
99
72
94
102
58
99
72
95
102
58
99
73
95
102
Table 30: Scenarios II: Levelized costs (in year 2011 dollars) versus the operational lifetime of the power plant.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
41
Scenarios I: Sensitivity of Levelized Cost to Capacity Factor
160
Coal
Gas
Nuclear
140
dollars per MWh
120
100
80
60
40
20
0
70
73
76
79
82
85
capacity factor
88
91
94
Figure 21: Scenarios I: Levelized costs (in year 2011 dollars) versus the lifetime capacity factor for the power
plant.
Coal
Gas
Nuclear
70%
73%
76%
79%
82%
85%
88%
91%
94%
66
66
111
65
65
107
63
64
103
62
64
99
60
63
96
59
62
93
58
62
90
57
62
87
56
61
85
Table 31: Scenarios I: Levelized costs (in year 2011 dollars) versus the lifetime capacity factor for the power
plant.
A REVIEW
42
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Scenarios II: Sensitivity of Levelized Cost to Capacity Factor
200
Coal
IGCC
Gas
NGCC
Nuclear
180
160
dollars per MWh
140
120
100
80
60
40
20
0
70
73
76
79
82
85
capacity factor
88
91
94
Figure 22: Scenarios II: Levelized costs (in year 2011 dollars) versus the lifetime capacity factor for the power
plant.
Coal
IGCC
Gas
NGCC
Nuclear
70%
73%
76%
79%
82%
85%
88%
91%
94%
69
120
71
98
133
67
116
71
97
128
65
113
70
95
124
64
110
69
94
120
62
107
69
93
116
61
105
68
92
112
60
102
68
91
109
58
100
67
90
105
57
98
67
89
102
Table 32: Scenarios II: Levelized costs (in year 2011 dollars) versus the lifetime capacity factor for the power
plant.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
43
Scenarios I: Sensitivity of Levelized Cost to the Hurdle Rate (WACC)
160
Coal
Gas
Nuclear
140
dollars per MWh
120
100
80
60
40
20
0
2
3
4
5
6
7
8
9
percent
10
11
12
13
14
15
Figure 23: Scenarios I: Levelized costs (in year 2011 dollars) versus the hurdle rate (WACC) for the power plant.
Coal
Gas
Nuclear
2%
3%
4%
5%
6%
7%
8%
9%
10%
11%
12%
13%
14%
15%
43
61
43
45
61
47
48
61
52
52
61
58
56
62
65
60
63
72
65
64
81
71
65
90
76
66
100
82
68
110
89
69
122
95
71
134
102
73
146
110
75
160
Table 33: Scenarios I: Levelized costs (in year 2011 dollars) versus the hurdle rate (WACC) for the power plant.
A REVIEW
44
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Scenarios II: Sensitivity of Levelized Cost to the Hurdle Rate (WACC)
220
Coal
IGCC
Gas
NGCC
Nuclear
200
180
dollars per MWh
160
140
120
100
80
60
40
20
0
2
3
4
5
6
7
8
9
percent
10
11
12
13
14
15
Figure 24: Scenarios II: Levelized costs (in year 2011 dollars) versus the hurdle rate (WACC) for the power
plant.
Coal
IGCC
Gas
NGCC
Nuclear
2%
3%
4%
5%
6%
7%
8%
9%
10%
11%
12%
13%
14%
15%
42
69
66
83
49
45
74
66
84
55
49
81
67
86
61
53
89
67
88
68
57
98
68
90
77
63
108
69
93
86
68
119
70
96
97
75
130
71
99
108
81
143
73
103
121
88
156
74
107
134
96
170
76
112
149
104
185
78
116
164
112
200
80
121
180
120
216
83
126
197
Table 34: Scenarios II: Levelized costs (in year 2011 dollars) versus the hurdle rate (WACC) for the power plant.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
45
Scenarios I: Sensitivity of Levelized Cost to Cost of CO2 Emissions
180
Coal
Gas
Nuclear
160
dollars per MWh
140
120
100
80
60
40
20
0
0
15
30
45
60
75
90
105
amount of hypothetical CO2 charge in constant 2011 dollars
120
Figure 25: Scenarios I: Levelized costs (in year 2011 dollars) versus hypothetical charges on CO2 emissions
ranging from 0 to $120 per ton. The dark vertical line corresponds to the CO2 charges in the Scenarios I base
case (0).
Coal
Gas
Nuclear
0
15
30
45
60
75
90
105
120
88
62
59
88
68
72
88
74
86
88
80
100
88
86
113
88
92
127
88
97
140
88
103
154
88
109
167
Table 35: Scenarios I: Levelized costs (in year 2011 dollars) versus hypothetical charges on CO2 emissions
ranging from 0 to $120 per ton.
A REVIEW
46
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Scenarios II: Sensitivity of Levelized Cost to Cost of CO2 Emissions
180
Coal
IGCC
Gas
NGCC
Nuclear
160
dollars per MWh
140
120
100
80
60
40
20
0
0
15
30
45
60
75
90
105
amount of hypothetical CO2 charge in constant 2011 dollars
120
Figure 26: Scenarios II: Levelized costs (in year 2011 dollars) versus hypothetical charges on CO2 emissions
ranging from 0 to $120 per ton. The dark vertical line corresponds to the CO2 charges in the Scenarios I base
case (0).
Coal
IGCC
Gas
NGCC
Nuclear
0
15
30
45
60
75
90
105
120
61
105
68
92
106
74
106
74
92
106
88
108
80
93
106
101
109
87
94
106
115
111
93
94
106
128
113
99
95
106
141
114
105
96
106
155
116
111
96
106
168
118
117
97
106
Table 36: Scenarios I: Levelized costs (in year 2011 dollars) versus hypothetical charges on CO2 emissions
ranging from 0 to $120 per ton..
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
47
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
60
80
84.1
49.54
20
40
38.7
0
dollars per MWh
100
120
140
Scenarios I: Low Fuel Cost Case
Coal
Gas
Nuclear
Figure 27: Levelized costs ($/MWh) in the Scenarios I low fuel cost case.
Coal
Gas
Nuclear
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
27.00
3.89
4.88
4.40
9.38
0.00
0.00
0.00
9.95
1.66
0.63
2.69
23.78
0.00
0.00
0.00
63.24
5.45
0.57
9.70
4.19
0.73
0.00
0.22
Total
49.54
38.70
84.10
Table 37: Levelized costs ($/MWh) in the Scenarios I low fuel cost case.
A REVIEW
48
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
120
140
Scenarios II: Low Fuel Cost Case
93.28
80
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
60
65.45
51.58
20
40
43.77
0
dollars per MWh
100
102.24
Coal
IGCC
Gas
NGCC
Nuclear
Figure 28: Levelized costs ($/MWh) in the Scenarios II low fuel cost case.
Coal
IGCC
Gas
NGCC
Nuclear
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
31.61
5.51
5.16
9.30
0.00
0.00
0.00
59.51
10.41
12.04
11.31
0.00
0.00
0.00
11.30
5.00
2.82
24.65
0.00
0.00
0.00
23.81
9.39
5.93
26.31
0.00
0.00
0.00
80.02
2.62
14.40
4.19
0.73
0.00
0.28
Total
51.58
93.28
43.77
65.45
102.24
Table 38: Levelized costs ($/MWh) in the Scenarios II low fuel cost case.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
49
120
140
Scenarios I: High Fuel Cost Case
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
77.67
20
40
60
80
96.67
0
dollars per MWh
100
110.03
Coal
Gas
Nuclear
Figure 29: Levelized costs ($/MWh) in the Scenarios I high fuel cost case.
Coal
Gas
Nuclear
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
27.00
3.89
4.88
4.40
37.51
0.00
0.00
0.00
9.95
1.66
0.63
2.69
95.10
0.00
0.00
0.00
63.24
5.45
0.57
9.70
16.77
0.73
0.00
0.22
Total
77.67
110.03
96.67
Table 39: Levelized costs ($/MWh) in the Scenarios I high fuel cost case.
A REVIEW
50
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
Scenarios II: High Fuel Cost Case
140
144.39
120
127.21
117.72
79.49
20
40
60
80
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
0
dollars per MWh
100
114.81
Coal
IGCC
Gas
NGCC
Nuclear
Figure 30: Levelized costs ($/MWh) in the Scenarios II high fuel cost case.
Coal
IGCC
Gas
NGCC
Nuclear
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
31.61
5.51
5.16
37.21
0.00
0.00
0.00
59.51
10.41
12.04
45.25
0.00
0.00
0.00
11.30
5.00
2.82
98.60
0.00
0.00
0.00
23.81
9.39
5.93
105.26
0.00
0.00
0.00
80.02
2.62
14.40
16.77
0.73
0.00
0.28
Total
79.49
127.21
117.72
144.39
114.81
Table 40: Levelized costs ($/MWh) in the Scenarios II high fuel cost case.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
51
88.29
80
83.16
20
40
60
72.89
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
0
dollars per MWh
100
120
140
Scenarios I: Low CO2 Emissions Cost Case
Coal
Gas
Nuclear
Figure 31: Levelized costs ($/MWh) in the Scenarios I low CO2 cost case.
Coal
Gas
Nuclear
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
27.00
3.89
4.88
4.40
18.75
0.00
24.24
0.00
9.95
1.66
0.63
2.69
47.55
0.00
10.41
0.00
63.24
5.45
0.57
9.70
8.38
0.73
0.00
0.22
Total
83.16
72.89
88.29
Table 41: Levelized costs ($/MWh) in the Scenarios I low CO2 cost case.
A REVIEW
52
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
120
140
Scenarios II: Low CO2 Emissions Cost Case
107.51
92.91
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
84.93
20
40
60
80
79.21
0
dollars per MWh
100
106.43
Coal
IGCC
Gas
NGCC
Nuclear
Figure 32: Levelized costs ($/MWh) in the Scenarios II low CO2 cost case.
Coal
IGCC
Gas
NGCC
Nuclear
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
31.61
5.51
5.16
18.61
0.00
24.05
0.00
59.51
10.41
12.04
22.62
0.00
2.92
0.00
11.30
5.00
2.82
49.30
0.00
10.79
0.00
23.81
9.39
5.93
52.63
0.00
1.15
0.00
80.02
2.62
14.40
8.38
0.73
0.00
0.28
Total
84.93
107.51
79.21
92.91
106.43
Table 42: Levelized costs ($/MWh) in the Scenarios II low CO2 cost case.
6. BREAKDOWN
OF
LCOE
FOR
VARIATIONS
ON
BASE CASES
53
120
140
Scenarios I: High CO2 Emissions Cost Case
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
88.29
60
80
83.29
0
20
40
dollars per MWh
100
107.4
Coal
Gas
Nuclear
Figure 33: Levelized costs ($/MWh) in the Scenarios I high CO2 cost case.
Coal
Gas
Nuclear
Construction
Incremental
Variable
Fixed
Fuel
Waste
Emissions
Decommission
27.00
3.89
4.88
4.40
18.75
0.00
48.48
0.00
9.95
1.66
0.63
2.69
47.55
0.00
20.81
0.00
63.24
5.45
0.57
9.70
8.38
0.73
0.00
0.22
Total
107.40
83.29
88.29
Table 43: Levelized costs ($/MWh) in the Scenarios I high CO2 cost case.
b
A REVIEW
54
OF THE
COSTS
OF
NUCLEAR POWER GENERATION
120
140
Scenarios II: High CO2 Emissions Cost Case
110.44
106.43
94.07
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
20
40
60
80
90
0
dollars per MWh
100
108.98
Coal
IGCC
Gas
NGCC
Nuclear
Figure 34: Levelized costs ($/MWh) in the Scenarios II high CO2 cost case.
Coal
IGCC
Gas
NGCC
Nuclear
Construction
Variable
Fixed
Fuel
Waste
Emissions
Decommission
31.61
5.51
5.16
18.61
0.00
48.10
0.00
59.51
10.41
12.04
22.62
0.00
5.85
0.00
11.30
5.00
2.82
49.30
0.00
21.58
0.00
23.81
9.39
5.93
52.63
0.00
2.30
0.00
80.02
2.62
14.40
8.38
0.73
0.00
0.28
Total
108.98
110.44
90.00
94.07
106.43
Table 44: Levelized costs ($/MWh) in the Scenarios II high CO2 cost case.
7. MODEL
OF
UNCERTAIN FUEL PRICES
55
7. Model of Uncertain Fuel Prices
Part of the analysis in this report uses a model of uncertain fuel prices. We use a stochastic process
call geometric Brownian motion for this purpose. We note that although this model is one of the most
tractable and popular, there are a number of competing models and a great deal of debate over which
is the most appropriate.
Denote the price of a commodity (e.g. natural gas or coal) at time t by P(t). Then P(t) is called a
geometric Brownian motion (GBM) if it satisfies:
dP(t) = µP(t) dt + σP(t) dz(t) .
(8)
The constants µ and σ are called the drift and volatility respectively. The drift relates to how the
expected price changes over time in this model, while the volatility relates to how large the price “steps”
are from one point to the next.
A fundamental result in stochastic calculus, known as Itô’s Lemma, can be used to show that (8)
implies
dlog P(t) = (µ − σ2 /2) dt + σ dz(t) .
(9)
∆ log P(t) = µ − σ2 /2 + σ"(t)
(10)
Equation (9) then implies
The GBM model implies that (instantaneous) percentage changes in price, rather than price itself,
follow a continuous random walk with drift. An important implication is that prices that start positive
remain positive with certainty.
We use historical coal and natural gas prices
to calibrate
the model (i.e. to determine appropriate
€
Š
2
values for the drift and volatility). Let m = µ − σ /2 . The maximum likelihood estimators for m and
σ2 are
m̂ =
σ̂2 =
T
1X
T
(11)
t=1
T
1X
T
∆ log P(t),
2
∆ log P(t) − m̂ ,
(12)
t=1
µ̂ = m̂ + σ̂2 /2.
(13)
The GBM model implies that future prices are lognormally distributed (i.e. the natural logarithm of
future prices is normally distributed). Both the mean and variance of future prices depend on the
current price and on how far in the future the future prices occur. The variance of future prices increases
with this time horizon, meaning that future prices are less predictable the farther into the future they
occur. Using t to represent some future time and s to represent some time prior to t, the statements in
this paragraph can be written as
€
Š
P(t) | P (s) = LogNormal log P(s) + (t − s) µ − σ2 /2 , tσ2 ,
(14)
where ∗| ∗ ∗ is the distribution of ∗, given ∗∗.
The expected future price at time t, given the price at time s, is called the conditional expected
value and is denoted E P(t) | P(s) . Similarly, the standard deviation of price at t, given the price at
time s, is called the conditional standard deviation and is denoted S P(t) | P(s) . They are determined
as follows:
A REVIEW
56
E P(t) | P(s) = P(s) exp µ (t − s) ,
OF THE
COSTS
OF
S P(t) | P(s) = P(s)
NUCLEAR POWER GENERATION
q
€
Š
exp σ2 (t − s) − 1.
(15)
Thus, the “one-step” mean and standard deviation (i.e. when s = t − 1 are):
E P(t) | P(t − 1) = P(t − 1) exp µ ,
S P(t) | P(t − 1) = P(t − 1) exp µ
q
€ Š
exp σ2 − 1. (16)
!
‚
Œ
σ2
2
P(t) | P(s) ∼LogNormal log P(s) + (t − s) µ −
, (t − s) σ
2
(17)
To simulate the price at any future time t, starting from some initial time s = t 0 , we draw a
lognormal (pseudo) random variable with the parameters given above.
Though we can do this in increments as fine as we like, the sequence of prices resulting from such
a sequence of draws is not a path. To simulate paths for GBM, we use the following discretized form of
equation (8):
Pt = 1 + µ Pt−1 + σPt−1 " t .
(18)
Here, " t is a standard normal random variable.
Table 45 shows the estimates of µ and σ for natural gas and coal. Inserting these values into
Equation 18, we obtain the following calibrated models for natural gas and coal:
p
Pt = (1.0251) Pt−1 + 0.0258Pt−1 " t
(natural gas)
(19)
p
Pt = (1.00742) Pt−1 + 0.008Pt−1 " t
(coal)
(20)
Table 45: Estimates of the GBM parameters for the coal and natural gas price models. Estimates for the natural
gas model are based on inflation-adjusted (year 2011) wellhead prices from 1950–2011, while estimates for the
coal model are based on inflation-adjusted (year 2011) prices from 1950–2010.
Parameters
m
µ
σ2
Natural Gas
Coal
0.0122
0.0251
0.0258
0.00343
0.00742
0.00800
Notes
1
The $850 per KWh given by MIT 2009 is the sum of the EPC and owner’s costs. Owner’s costs are estimated as
20 percent of EPC. Thus the adjusted estimate is 1.2 × (0.8 × $850) × 1.15 × inflation factor = $1, 008.
2
There will also have been some pre-construction planning, but although these activities can go on for a considerable period of time, costs associated with planning will ordinarily be a small fraction of total plant costs.
3
Of the 104 operating reactors, 66 have already obtained 20-year extensions on their original 40-year operating
license, and 16 have filed with NRC for renewal.
REFERENCES
57
4
The State of Utah currently waives the state corporate income tax for nuclear power plants.
5
Note that the adjustment does not involve subtracting 3 percent from the MIT nominal rates and then adding 1.8
percent back, as that fails to account for the change in basis. The following are the details of the adjustment: Let
π be the MIT rate of inflation, π̄ the rate of inflation assumed in this report, g r the inflation-adjusted rate, g n the
1+g
MIT nominal rate, and ḡ n the nominal rate used in this report. By definition, g r = 1+πn − 1. Since the objective
is to retain the inflation-adjusted rates of MIT 2009, what is done is to set g n = 0.15 for MIT’s nominal rate of
return for equity and π = 0.03 for MIT’s inflation rate, π̄ = 0.018 for the rate of inflation of this report, and solve
1+ḡ n
(1+0.018)(1+0.15)
= 1+0.018
, which implies ḡ n =
− 1 = 0.1366.
for ḡ n in an equality of g r : 1+0.15
1+0.03
1+0.03
6
The Energy Information Agency publication Carbon Dioxide Emission Factors for Coal EIA 1994, reports on the
carbon content of a large number of coal samples taken from various parts of the U.S. The publication does not
report the carbon content of these samples by region, but rather gives the average pounds of carbon dioxide
resulting from combustion of 1 MMBTU of regional coal. For the Utah samples, this number was 204.1. The
implied carbon
content factor, f , for 11,700 BTU/lb. coal is determined by solving f × 1,000,000/11,700 ×
44.01/12.01 = 204.1. Thus, this coal is 65 percent carbon by weight.
7
1,000 × 1,000/1,026 × 0.042 × 0.76 × 44.01/12.01 = 114.
8
Since 1 MWh is equivalent to 3.412 MMBTU, the coal plant in this case can be seen as extracting 38 percent of
the energy. The gas plant is more efficient, extracting 50 percent of the energy in the natural gas.
References
[EIA 1994]
B.D. Hong and E.R. Slatick. Carbon Dioxide Emission Factors for Coal. 1994.
[EIA 2010]
Energy Information Administration. Updated Capital Cost Estimates for Electricity
Generation Plants. 2010.
[Kidd 2008]
Steve Kidd. Escalating costs of new build: what does it mean? 2008.
[MIT 2003]
Massachusetts Institute of Technology. The Future of Nuclear Power: An Interdisciplinary Study. 2003.
[MIT 2009]
Massachusetts Institute of Technology. Update of the MIT 2003 Future of Nuclear
Power. 2009.
[PacifiCorp 2011]
[UC 2004]
[WNA 2011]
PacifiCorp. 2011 Integrated Resource Plan. 2011.
University of Chicago. The Economic Future of Nuclear Power. 2004.
World Nuclear Association. The Economics of Nuclear Power. 2011.