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Review of OECD study into ‘‘Projected costs of generating electricity—2010
Edition’’
Hisham Khatib
Global Energy Award Laureate (2007), P.O. Box 410, Amman 11831, Jordan
a r t i c l e in fo
abstract
Article history:
Received 6 May 2010
Accepted 9 May 2010
This joint report by the International Energy Agency (IEA) and the OECD Nuclear Energy Agency (NEA) is
the seventh in the long established series of studies into electricity generating costs. It presents the
main results of the work carried out in 2009 for calculating the costs of generating baseload electricity.
The study is quite comprehensive in covering almost all financial aspects facing investors in the
electricity generating system. Therefore this study although useful, its usefulness lies in explaining
methodologies, mentioning factors that affect investment and cost, educating planners and improving
investment evaluation and planning methodologies, its resulting figures and cost comparisons are
however controversial. Generation planning and investments are case and country specific, and should
be studied correspondingly and as close as possible to the timing of decision making to take account of
trends. Most likely such case specific results will differ from figures calculated in the study. Therefore
we need to emphasize a key conclusion of the study which is ‘‘that country-specific circumstances
determine the LCOE’’; it is this that needs to be considered and not the results represented in the study.
& 2010 Elsevier Ltd. All rights reserved.
Keywords:
Electricity
Generating plant
Economics
This joint report by the International Energy Agency (IEA) and
the OECD Nuclear Energy Agency (NEA) is the seventh in the long
established series of studies into electricity generating costs. It is
referred to later as the ‘‘study’’.
Projected Costs of Generating Electricity—2010 Edition (OECD,
2010) presents the main results of the work carried out in 2009
for calculating the costs of generating baseload electricity from
nuclear and fossil fuel thermal power stations as well as the costs
of generating electricity from a wide range of renewable
technologies. All of the included technologies are expected to be
commissioned by 2015. The work was conducted under the
supervision of the Ad hoc Expert Group on Electricity Generating
Costs which was composed of representatives of the participating
OECD member countries, experts from the industry and academia
as well as from the European Commission and the International
Atomic Energy Agency (IAEA).
This review is in two parts. Part I directly quotes the main
assumptions and conclusions of the study as outlined in its
Executive Summary. Part II is a critical evaluation of some of the
assumptions and methodologies adopted in this study as well as
its conclusions.
E-mail address: [email protected]
1. Part I—Study assumptions, methodologies and main
conclusions
1.1. Methodology and generic assumptions
The study focuses on the expected plant-level costs of base
load electricity generation by power plants that could be
commissioned by 2015. It also includes the generating costs of a
wide range of renewable energy sources, some of which have
variable output. In addition, the report covers projected costs
related to advanced power plants of innovative designs, namely
commercial plants equipped with carbon capture, which might
reach the level of commercial availability and be commissioned
by 2020. Cost data provided by the experts were compiled and
used to calculate the levelised costs of electricity (LCOE) for base
load power generation.
The calculations are based on the simple levelised average
(unit) lifetime cost approach, using the discounted cash flow
(DCF) method. The most important assumptions concern the
utilization of two real discount rates, 5% and 10% (common to all
technologies), also keeping with tradition, fuel prices and, for the
first time, a carbon price of $ 30 per ton of CO2.
The study reaches two important conclusions (see Figs. 1 and 2
below). First, in the low discount rate case, more capital-intensive,
low-carbon technologies such as nuclear energy are the most
competitive solutions compared with coal-fired plants without
carbon capture and natural gas-fired combined cycle plants for
0301-4215/$ - see front matter & 2010 Elsevier Ltd. All rights reserved.
doi:10.1016/j.enpol.2010.05.023
Please cite this article as: Khatib, H., Review of OECD study into ‘‘Projected costs of generating electricity—2010 Edition’’. Energy
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Fig. 1. Regional ranges of LCOE for nuclear, coal, gas and onshore wind power plants (at 5% discount rate).
Fig. 2. Regional ranges of LCOE for nuclear, coal, gas and onshore wind power plants (at 10% discount rate).
base load generation. It should be emphasized that these results
incorporate a carbon price of $ 30 per ton of CO2.
Second, in the high discount rate case, coal without carbon
capture equipment, followed by coal with carbon capture
equipment, and gas-fired combined cycle turbines (CCGTs),
are the cheapest sources of electricity. In the high discount
rate case, coal without CC(S) is always cheaper than coal with
CC(S), even in low-cost coal regions, at a carbon price of $ 30 per
ton. The results highlight the paramount importance of discount
rates and, to a lesser extent, carbon and fuel prices when
comparing different technologies. The study also includes extensive sensitivity analyses to test the relative impact of
variations in key cost parameters (such as discount rates,
construction costs, fuel and carbon prices, load factors, lifetimes
and lead times for construction) on the economics of different
generating technologies individually considered.
The electricity generation costs calculated are plant-level (busbar)
costs, at the station, and do not include transmission and distribution
costs. Finally, the cost estimates do not include any external costs
associated either with residual emissions (other than CO2 emissions)
or impacts on the security of supply. A key conclusion is that countryspecific circumstances determine the LCOE.
1.2. Main results
The most important results is the fact that nuclear, coal, gas
and, where local conditions are favorable, hydro and wind, are
Please cite this article as: Khatib, H., Review of OECD study into ‘‘Projected costs of generating electricity—2010 Edition’’. Energy
Policy (2010), doi:10.1016/j.enpol.2010.05.023
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now fairly competitive generation technologies for base load
power generation. Their precise cost competitiveness depends
more than anything on the local characteristics of each particular
market and their associated cost of financing, as well as CO2
and fossil fuel prices. As mentioned earlier, the lower the cost
of financing, the better the performance of capital-intensive,
low-carbon technologies such as nuclear, wind or CC(S); at
higher rates, coal without CC(S) and gas will be more competitive.
In the view of the study there is no technology that has a
clear overall advantage globally or even regionally. Each one of
these technologies has potentially decisive strengths and
weaknesses that are not always reflected in the LCOE figures
provided in the study.
3
2. Part II—critical evaluation
It must be emphasized that this 2010 edition is a comprehensive study. It deals not only with the methodology, conclusions
and technology review; but it also covers country-by-country
data, sensitivity analyses, financing issues, working of actual
power markets and carbon capture and storage. The study covers
in an extensive way renewable power generation and its system
integration. These sources, in spite of their modest contribution,
are gaining increasing attention in OECD countries and apparently
the study recognizes this in a rather extensive analysis.
In the following section, I will present a critical review of some
of the study’s assumptions; these include: common discount
rates, decommissioning costs, fuel and carbon prices, reference
year, as well as the way in dealing with system and other costs.
1.3. Conclusions of the study
The levelised costs and the relative competitiveness of
different power generation technologies in each country are
highly sensitive to the discount rate and slightly less, but still
significantly sensitive, to the projected prices for CO2, natural gas
and coal. For renewable energy technologies, country- and sitespecific load factors also play an important role.
With the liberalization of electricity markets, certain risks have
become more transparent, so that project proponents must now
bear and closely manage these risks (to the extent that they can
no longer be transferred to consumers or taxpayers). This has
implications for determining the required rate of return on
generation investments. Access to financing and national support
policies for individual technologies designed to reduce financing
risks (such as feed-in tariffs, loan or price guarantees) are thus
likely to play an important role in determining final power
generation choices. Environmental policy will also play an
increasingly important role that is likely to significantly influence
fossil fuel costs in the future and the relative competitiveness of
various generation technologies. In addition, the markets for
natural gas are undergoing substantial changes on many levels
which make current projections for prices even more uncertain
than usual. Also, coal markets are being influenced by new factors.
Security of energy supply remains a concern for most OECD
countries and may be reflected in government policies affecting
generating investment in the future.
The study provides insights into the relative costs of generating technologies in the participating countries and reflects the
limitations of the methodology and the generic assumptions
employed. The limitations inherent in the approach are stressed
in the report. In particular, the cost estimates presented do not
represent the precise costs which would be calculated by
potential investors for any specific project. Together with national
energy policies favouring or discouraging specific technologies,
the investors’ concern about risk is one of the reasons explaining
the difference between the study’s findings and the market
preference for gas-fired technologies. Different fuel price expectations may also affect investors’ decisions in some markets.
Within this framework and various limitations, the study
suggests that no single electricity generating technology can be
expected to be the cheapest in all situations. The preferred
generating technology will depend on a number of key parameters and the specific circumstances of each project. This edition
of Projected Costs of Generating Electricity indicates that the
investors’ choice of a specific portfolio of power generation
technologies will most likely depend on financing costs, fuel and
carbon prices, as well as the specific energy policy context
(security of supply, CO2 emissions reductions, market framework).
2.1. Discount rates
Discounting is the most important aspect in project evaluation
and choices of the least cost project (Khatib, 2003). The
methodology adopted in the study is based on a fixed discount
rate (5% or 10%) common to all forms of considered generation
technologies. This is a controversial approach.
As is well known the discount rate, is the opportunity cost of
capital (as a percentage of the value of the capital). In turn the
opportunity cost of capital is the return on investments forgone
elsewhere by committing capital to the project under consideration. It is also referred to as the marginal productivity of capital,
i.e. the rate of return which would have been obtained by the last
acceptable project. In investment decisions, the opportunity cost
of capital is the cut-off rate, below which it is not worthwhile to
invest in the project.
To serve this purpose, the nominal discount rate should be
equal to at least a value which, after tax, would provide the
investor with the following: (i) compensation for a reduction in
the purchasing power of money which is brought about by
inflation, (ii) a real return, (iii) compensation for the extent of risk
undertaken by committing capital to this investment. The value of
the nominal discount rate is correspondingly a function of the
above three factors, namely inflation, risk-free real return and the
extent of risk in the project (or technology). The methodology of
the study opted to chose a real discount rate, which ignores
inflation. When reference is made to the discount rate, then it is
the real discount rate that is meant.
But by choosing a common discount rate that applies to
different generating technologies, and investment decisions, the
methodology ignored the most important aspect of choosing a
discount rate which is the ‘‘compensation for the extent of risk of
this type of generation technology’’. Is the risk of investing in
nuclear facilities the same as investing in CCGT, or does investing
in a traditional coal plant carry the same risk as investing in the
yet un-established new technologies of renewable plants; are the
long term risks of investing in traditional carbon emitting
technologies similar to new technologies with carbon capture
and storage (CCS)? In my view, definitely not. Nuclear facilities
(because of its capital intensive nature, long execution time and
public controversies) carry more investment risk than that of
conventional facilities, and investing in a carbon emitting coal
plant can pose a higher long term risks to an investor (carbon
taxation) than in building a cleaner gas firing plant. Different
generating technologies have different risks; correspondingly
discount rate(s) utilized should be different for each form of
generation technology to connote the perceived risk in investing
in this technology.
Please cite this article as: Khatib, H., Review of OECD study into ‘‘Projected costs of generating electricity—2010 Edition’’. Energy
Policy (2010), doi:10.1016/j.enpol.2010.05.023
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Increasingly investing in generation facilities is being undertaken by the private sector through independent power producers
(IPPs) or private–public partnership (PPP) where the perceived
risk of the investment carries a primary role in decision making,
like what takes place in financial markets.
In the financial market a stock’s sensitivity to change in the
value of the market portfolio is known as ‘‘beta’’. Beta, therefore,
measures the marginal contribution of a stock to the risk of a
market portfolio. In a competitive market, the expected risk
premium varies in direct proportion to beta. This is the capital
asset pricing model (Bealey and Myers, 2000), usually referred to
as (CAPM).
Expected risk premium on a stock¼beta expected risk
premium on market.
Therefore, treasury bills have a beta of zero because they do
not carry any risk. The average equity in the market portfolio has
a beta of 1.
Generally speaking:
Expected risk premium on investment ¼ beta average
market risk premium. Real discount rate ¼ real risk-free rate
+ (market risk premium beta).
Fig. 3. Sensitivity of nuclear and coal power station costs to discount rate
(Following assumptions of Dimson 1989).
Investment cost (pounds million)
Operating costs/kWh
Fuel cost/kWh (ignoring carbon cost)
Nuclear
Coal
1527
0.37 p
0.45 p
895
0.46 p
1.43 p
p (pence) ¼0.01 pounds sterling ¼1.5 US cents.
Apparently, no general global figure can be put into the beta of
every generation technology or a new facility. Generation utilities
have a higher risk and correspondingly higher beta value than
distribution utilities. Nuclear has a higher risk than other forms of
thermal generation and, correspondingly, utilities with nuclear
generation have a higher beta than other generating utilities,
depending on the extent of their nuclear component. New
renewable facilities carry more investment risk than well established CCGT gas-firing facilities. Because of the uncertainty about
future carbon pricing, investing in large long lead time pulverized
coal-firing and heavy carbon emitting generating units is riskier
than investing in smaller short lead time CCGT plant firing cleaner
gas and which easily fits the load curve. Therefore the discount
rate(s) to be utilized in comparing different generation technologies needs to be calculated in a CAPM methodology depending on a
beta for each technology which can lead to a different discount rate
for each new facility technology.
It is these risks, as reflected in different ‘‘beta’’ and correspondingly a different discount rate, which can differ from one
technology to another, are the main concerns of the investor.
Obviously, the discount rate is crucial in such decision making
between alternatives, as demonstrated in the following Fig. 3
(Dimson 1989).
The figure demonstrates the important fact of the sensitivity of
the cost of different types of technologies to the choice of the
discount rate. It is clear that, because future net benefits are
greatly reduced by the higher discount rate, the cost per kWh
rises for capital intensive nuclear power stations more rapidly
than it does for the less capital but higher operating cost coal
power stations. For low operating cost alternatives, like nuclear,
the high net benefits are severely eroded by the high discount
rate, although the high up front capital investment is compounded by the high discount rate to the base year of
commissioning. For the higher operating cost alternative, the
net benefits as well as the up front investment are smaller and,
correspondingly, the result is less affected by discounting. The
choice of the proper interest rate is crucial in such highly different
investment cost alternatives.
The fact that the study assesses different technologies, by the
same common discount rate disregarding the market and their
technology risk, is one of the study’s weak points.
2.2. Decommissioning
A major element of cost and risk consideration in investing in
nuclear facilities is the decommissioning costs of the nuclear
power plant. The study states that a generic assumption of 15% of
the construction cost has been applied to calculate the costs
incurred during all the management and technical actions
associated with ceasing operation of a nuclear installation and
its subsequent dismantling to obtain its removal from regulatory
control. Disbursed during the ten years following shut-down, the
decommissioning cost is discounted back to the date of commissioning and incorporated in the overall levelised costs. While an
incontestably important element of nuclear power plant’s operation, due to the effect of discounting, decommissioning accounts
for a smaller portion of the LCOE. In particular, the fact is that for
nuclear power plants decommissioning costs are due after 60
years of operation, discounting them back to the commissioning
date, makes the net present value of decommissioning close to
zero, even when applying lower discount rates or assuming much
higher decommissioning costs.
Correspondingly the study actually considers the cost of
decommissioning of nuclear power plants to be zero for today’s
decisions. Is that a correct and fair treatment for investment
decisions? Does it not represent shifting problems made by the
present generation into the shoulders of the future generation,
which is contrary to be basic assumptions of sustainable
development. The investor of today does not care about costs
incurred after sixty years however serious they were. It is others
who have to wrestle with this problem and bear its substantial
costs when it looms in the long term. Most likely it is going to be
heavy social costs. Therefore the study’s practical assumption
(brought out by discounting), that decommissioning costs are
negligible for today’s decisions, is not fair, to say the least.
Decommissioning costs, particularly of nuclear plants, have to
be taken into account in today’s investment decisions. This can take
many forms; one of them is to account for these costs with a ‘‘social
discount rate’’ of zero. So that their estimated value will be fully
incorporated in today’s investment costs, without discounting. An
alternative arrangement is to account for them in the risk factor
‘‘beta’’. If today two plants have similar investment and operational
Please cite this article as: Khatib, H., Review of OECD study into ‘‘Projected costs of generating electricity—2010 Edition’’. Energy
Policy (2010), doi:10.1016/j.enpol.2010.05.023
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costs, the one with the high decommissioning cost needs to have a
higher ‘beta’ than the other plant. The decommissioning cost will
be reflected in having a different beta and correspondingly higher
discount rate and lower benefits of the future income stream for
plants with high long term decommissioning cost.
2.3. Carbon price and fuel prices
The study allocates carbon price of $ 30 per ton of CO2 in OECD
countries. Presently carbon is traded in the EU ETS (European
Trading System) at less than $ 20 per ton. Carbon pricing and
trading is a highly unpredictable subject with its long term
prospects obscure. However pricing carbon, for comparing the
economics of different generating facilities, has tremendous
implications.
CO2 prices or costs are explicit in the European Union (EU)
with the introduction of the ETS in 2005. There are also
indications of investors in other OECD countries, for example in
the US, taking carbon pricing into account when making
investment decisions, on the expectation that such a price will
emerge in the future.
CO2 prices in the EU ETS have fluctuated between $ 10 and
$ 40/tCO2, reflecting great uncertainty, particularly regulatory
uncertainty and initial problems related to the start of the system,
but also reflecting competition between gas and coal, depending
on their relative prices.
The generic assumption for carbon prices was $ 30 per ton of
carbon in the study for all OECD countries and zero for nonmember countries.
The CO2 module of the study calculates the carbon cost per
MWh. Whenever available, national data on carbon emission per
MWh was used. Otherwise data were derived from the 2006 IPCC
Guidelines (IPCC, 2006). Typically, carbon emissions are around
100 tCO2/TJ for hard coal and 50 tCO2/TJ for gas. With standard
electric conversion factors of 40% and 55%, this amounts to
emission of 0.9 tCO2/MWh for electricity from hard coal and of
0.33 tCO2/MWh for electricity from gas-fired power generation.
The study concluded (Fig. 1) that average median LCOE for coal
plant in the US was around $ 72/MWh, of this carbon prices were
$ 27/MWh, i.e. around 38% of cost and more expensive than fuel
costs. In Europe the median was around $ 82/MWh of which
carbon prices were one third. These are very significant costs
which reflect the importance of carbon pricing in generation
costing, particularly for coal plant. A price of $ 30/ton of CO2, as
utilized in the study, cannot be generalized and each decision
must be considered on its own merits.
Price of fuel in the study is also disputed. This study assumes a
long-term OECD steam coal import cost of $ 90/ton, noting that
several OECD regions have costs well below this level and are not
subject to the fluctuations of international markets. For these
countries the study has used domestic coal prices for the
country’s levelised cost calculations, in particular for Australia
($ 26.65/t of hard coal), Mexico ($ 87.50/t of hard coal) and the
United States.
($ 47.60/t of hard coal), noting that in some regions of the US,
coal prices are significantly below this price.
However price of gas in this study, a generic natural gas import
price of $ 10.3/MMBtu was assumed for European imports and $
12.7 for Asian LNG. Domestic natural gas prices were applied in
producing regions, namely in North America ($7.78/MMBtu) and
Australia ($8/MMBtu). Such prices of natural gas are almost twice
the prices prevailing now (April 2010), which casts serious
shadow on the results of the study in case of costing output of
CCGT plants and invalidates some of its conclusions.
5
2.4. Reference year
The study is clear about the commissioning date (31.12.2015)
and all the discounting of the costs and benefits of the project are
allocated to that date. Costs and benefits are discounted according
to ‘‘t’’ which denotes the year in which the sale of production or
the cost of disbursement takes place compared to the commissioning date.
But we have to realize that not all costs and benefits occur at
the end of the year. The main benefits of electricity production,
which is generation in kilowatt hour (kWh), occur continuously
every hour of the year. To accumulate these as a single generation
figure at the end of the year, as implied in the study, is an
inaccurate approximation. Payments for salaries, fuel, etc. are
costs which are incurred monthly and continue throughout the
year. To lump them as a single payment at the end of the year and
to discount them will result in an underestimation. To overcome
this, such financial flows can be presented in a monthly form (or
hourly) which makes the calculation cumbersome. As an alternative, they can be lumped as an annual flow at the middle of the
year, which is a useful approximation.
Therefore, if the commissioning year is the last day of year
2015, then the cash flow of the first year has to be grouped at the
middle of year 2016 for present valuing purposes, and discounted
for half a year. The second year’s cash flow is grouped at 1.5 years
from the commissioning date, etc. Deviation from this, like the
common practice of grouping all cash flows at the end of the year,
causes some error.
2.5. Other costs
The study recognizes that there are other significant costs that
affect the comparison of LCOE of different plants. However these
are not included in the study since each case and site has its
particular costs.
However cost of transmission greatly influences the choice of
the least cost generation option. This particularly applies to
renewables which are sited in remote places, like wind turbines,
and many a time large solar plants are located in deserts. Many
renewables are severely penalized by transmission costs and
correspondingly abandoned.
The study also recognizes difficulties in incorporating renewals
in dispatching and building reserves in generation systems. No
specific costs are allocated to these since they have to be
considered individually. Correspondingly renewables, which
according to the study are already higher in cost than conventional plants, will be severely penalized when individually
considered with site locations and dispatching considerations.
Their LCOE can be much higher than that quoted in the study.
3. Part III—to conclude
The study is quite comprehensive in covering almost all
financial aspects facing investors in the electricity generating
system. It also deals with the effect of taxes, interest rates,
currency exchange rates, weighted average cost of capital
(WACC), inflation, impact of the recent economic recession, etc.
However as mentioned above and as the study recognizes, it
ignores external costs and cost of transmission and country
specific investment considerations particularly specific country
risk and technology risk. Most important are variations in fuel
prices, particularly recent reduction in the price of natural gas,
which has rendered some of its costing, particularly for CCGT
Please cite this article as: Khatib, H., Review of OECD study into ‘‘Projected costs of generating electricity—2010 Edition’’. Energy
Policy (2010), doi:10.1016/j.enpol.2010.05.023
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H. Khatib / Energy Policy ] (]]]]) ]]]–]]]
generation, out-of-date. This besides the important five reservations mentioned in Part II of this review.
Therefore this study although useful, its usefulness lies in
explaining methodologies, mentioning factors that affect investment and cost, educating planners and improving investment
evaluation and planning methodologies, its resulting figures and
cost comparisons are however controversial. Generation planning
and investments are case and country specific, and should be
studied correspondingly and as close as possible to the timing of
decision making to take account of trends. Most likely such case
specific results will differ from figures calculated in the study.
Therefore we need to emphasize a key conclusion of the study
which is ‘‘that country-specific circumstances determine the
LCOE’’; it is this that needs to be considered and not the results
represented in the study.
References
OECD, 2010. Projected Cost of Generating Electricity, 2010 edition.
Khatib, H., 2003. Financial and Economic Evaluation of Projects in the Electricity
Supply Industry.. Institution of Electrical Engineers, London 2003.
Bealey, R.A., Myers, S.C., 2000. Principles of Corporate Finance. McGraw Hill 2000.
Dimson, E., 1989. The discount rate of a power station. Energy Economics 11, 13.
IPCC, 2006. IPCC Guidelines for National Greenhouse Inventories, Chapter 2
‘‘Stationary Combustion’’, p 2.16.
Please cite this article as: Khatib, H., Review of OECD study into ‘‘Projected costs of generating electricity—2010 Edition’’. Energy
Policy (2010), doi:10.1016/j.enpol.2010.05.023