The Economics of Wind Energy By the European Wind Energy Association

The research team responsible for this report consists of: Søren Krohn, CEO, Søren Krohn Consulting, Denmark (editor); Dr. Shimon Awerbuch, Financial Economist, Science and Technology Policy Research, University of Sussex, United Kingdom. Poul Erik Morthorst, Senior Researcher, Risoe National Laboratory, Denmark.

This risk reduction from wind energy is presently not accounted for by standard methods for calculating the cost of energy, which have been used by public authorities for more than a century. Quite the contrary, current calculation methods blatantly favour the use of high-risk options for power generation. In a situation where the industrialised world is becoming ever more dependent on importing fuel from politically unstable areas at unpredictable and higher prices, this aspect merits immediate attention.

The average turbine installed in Europe has a total investment cost of around €1.23 million/MW. The turbine’s share of the total cost is, on average, around 76%, while grid connection accounts for around 9% and foundation for around 7%. The cost of acquiring a turbine site (on land) varies significantly between projects. Other cost components, such as control systems and land, account for only a minor share of total costs.

The total cost per kW of installed wind power capacity differs significantly between countries. The cost per kW typically varies from around €1,000/kW to €1,350/kW. The investment costs per kW were found to be the lowest in Denmark, and slightly higher in Greece and the Netherlands. For the UK, Spain and Germany, the costs in the data selection were found to be around 20-30% higher than in Denmark. Also, for “other costs”, such as foundation and grid connection, there is considerable variation between countries, ranging from around 32% of total turbine costs in Portugal, to 24% in Germany, 21% in Italy and only 16% in Denmark. However, costs vary depending on turbine size, as well as the country of installation, distance from grids, land ownership structure and the nature of the soil.

Based on experiences in Germany, Spain, the UK and Denmark, O&M costs are generally estimated to be around 1.2 to 1.5 eurocents (c€) per kWh of wind power produced over the total lifetime of a turbine. A developer of a wind farm has to compensate land owners for siting a wind turbine on their land which can be used for other purposes, such as farming. Generally speaking this cost is quite small, since wind farms usually only use about 1-2% of the land area of a wind farm for installation of turbines, transformers and access roads. This rental cost of land may either be included in the O&M costs of a wind farm or capitalised as an up front payment once and for all to the landowner.

In any case, the local wind climate is the most important factor in determining the cost of wind energy. In order to be cost-effective, each individual turbine has to be sited very carefully, taking account of not just local wind climate measurements, but also of nearby obstacles to the wind, such as woodland and buildings. Also, the roughness and ruggedness of the landscape play an important role in determining local wind speeds. Likewise the orography – that is, the varied curvature of the terrain surface – is essential. Generally speaking, wind turbines on rounded hilltops will produce more electricity than turbines located in valleys or rugged terrain, and turbines at sea or close to a shore will produce more energy than turbines located inland.

The capacity factor of a wind turbine or another electricity generating plant is the amount of energy delivered during a year divided by the amount of energy that would have been generated if the generator were running at maximum power output throughout all the 8,760 hours of a year.

The costs per kWh of wind-generated power, calculated as a function of the wind regime at the chosen sites, range from approximately 7-10 c€/kWh at sites with low average wind speeds, to approximately 5-6.5 c€/kWh at windy coastal sites, with an average of approximately 7c€/kWh at a wind site with average wind speeds.

As is demonstrated in this publication, markets will not solve these problems by themselves because markets do not properly value the external effects of power generation. Governments need to correct the market failures arising from external effects because costs and benefi ts for a household or a firm who buys or sells in the market are different from the cost and benefi ts to society. It is cheaper for power companies to dump their waste, e.g. in the form of fly ashes, CO2, nitrous oxides, sulphur oxides and methane for free. The problem is that it creates cost for others, e.g. in the form of lung disease, damage from acid rain or global warming. Similarly, the benefi ts of using wind energy accrue to the economy and society as a whole, and not to individual market participants (the so-called common goods problem).

This report provides a systematic framework for the economic dimension of wind energy and of the energy policy debate when comparing different power generation technologies. A second contribution is to put fuel price risk directly into the analysis of the optimal choice of energy sources for power generation. Adjusting for fuel-price risk when making cost comparisons between various energy technologies is unfortunately very uncommon and the approach is not yet applied at IEA, European Commission or government level. This report proposes a methodology for doing so. The methodology should be expanded to include carbon-price risk as well, especially given the European Union’s December 2008 agreement to introduce a real price on carbon pollution (100% auctioning of CO2 allowances in the power sector) in the EU.

1. Basic cost of wind energy

Approximately 75% of the total cost of energy for a wind turbine is related to upfront costs such as the cost of the turbine, foundation, electrical equipment, grid-connection and so on. Obviously, fl uctuating fuel costs have no impact on power generation costs. Thus a wind turbine is capital-intensive compared to conventional fossil fuel fi red technologies such as a natural gas power plant, where as much as 40-70% of costs are related to fuel and O&M.

Operation and maintenance (O&M) costs for onshore wind energy are generally estimated to be around 1.2 to 1.5 c€ per kWh of wind power produced over the total lifetime of a turbine. Spanish data indicates that less than 60% of this amount goes strictly to the O&M of the turbine and installations, with the rest equally distributed between labour costs and spare parts. The remaining 40% is split equally between insurance, land rental and overheads.

The costs per kWh of wind-generated power, calculated as a function of the wind regime at the chosen sites, range from approximately 7-10 c€/kWh at sites with low average wind speeds, to approximately 5-6.5 c€/kWh at windy coastal sites, with an average of approximately 7c€/kWh at a wind site with average wind speeds. The rapid European and global development of wind power capacity has had a strong infl uence on the cost of wind power over the last 20 years.

The economic consequences of the trend towards larger turbines and improved cost-effectiveness are clear. For a coastal site, for example, the average cost has decreased from around 9.2 c€ /kWh for the 95 kW turbine (mainly installed in the mid 1980s), to around 5.3 c€ /kWh for a fairly new 2,000 kW machine, an improvement of more than 40% (constant €2006 prices). Using the specifi c costs of energy as a basis (costs per kWh produced), the estimated progress ratios range from 0.83 to 0.91, corresponding to learning rates of 0.17 to 0.09. That means that when the total installed capacity of wind power doubles, the costs per kWh produced for new turbines goes down by between 9 and 17%.

Offshore wind currently accounts for a small amount of the total installed wind power capacity in the world – approximately 1%. The development of offshore wind has mainly been in northern European counties, around the North Sea and the Baltic Sea, where about 20 projects have been implemented. At the end of 2008, 1,471 MW of capacity was located offshore. Offshore wind capacity is still around 50% more expensive than onshore wind. However, due to the expected benefi ts of higher wind speeds and the lower visual impact of the larger turbines, several countries – predominantly in European Union Member States – have very ambitious goals concerning offshore wind.

Although the investment costs are considerably higher for offshore than for onshore wind farms, they are partly offset by a higher total electricity production from the turbines, due to higher offshore wind speeds. For an onshore installation utilisation, the energy production indicator is normally around 2,000-2,500 full load hours per year, while for a typical offshore installation this fi gure reaches up to 4,000 full load hours per year, depending on the site.

The market is expected to be stable at around €10 billion/year up to 2015, with a gradually increasing share of investments going to offshore. By 2020, the annual market for wind power capacity will have grown to €17 billion annually with approximately half of investments going to offshore. By 2030, annual wind energy investments in EU-27 will reach almost €20 billion with 60% of investments offshore.

It is assumed that wind energy avoids an average of 690g CO2/kWh produced; that the average price of a CO2 allowance is €25/t CO2 and that €42 million worth of fuel is avoided for each TWh of wind power produced, equivalent to an oil price throughout the period of $90 per barrel.


The general cost of conventional electricity production is determined by four components:

1. Fuel cost

2. Cost of CO2 emissions (as given by the European Trading System for CO2, the ETS)

3. O&M costs

4. Capital costs, including planning and site work In this report, fuel prices are given by the international markets and, in the reference case, are assumed to develop according to the IEA’s World Energy Outlook 2007, which assumes a crude oil price of $63/barrel in 2007, gradually declining to $59/barrel in 2010 (constant terms). As is normally observed, natural gas prices are assumed to follow the crude oil price (basic assumptions on other fuel prices: Coal €.6/GJ and natural gas €.05/GJ). Oil prices reached a high of $147/barrel in July 2008.

The natural gas price is assumed to double compared to the reference equivalent to an oil price of $118/barrel in 2010, the coal price to increase by 50% and the price of CO2 to increase to 35€/t from 25€/t in 2008. The competitiveness of wind-generated power increases signifi cantly with rising fuel and carbon prices; costs at the inland site become lower than generation costs for the natural gas plant and around 10% more expensive than the coal-fired plant. On coastal sites, wind power produces the cheapest electricity of the three.

The uncertainties mentioned above, related to future fossil fuel prices, imply a considerable risk for future generation costs of conventional plants. The calculations here do not include the macro-economic benefits of fuel price certainty, CO2 price certainty, portfolio effects, merit-order effects and so on. Even if wind power were more expensive per kWh, it might account for a significant share in the utilities’ portfolio of power plants since it hedges against unexpected rises in prices of fossil fuels and CO2 in the future. According to the International Energy Agency (IEA), a EU carbon price of €10 adds 1c€/kwh to the generating cost of coal and 0.5c€/kWh to the cost of gas generated electricity. Thus, the consistent nature of wind power costs justifies a relatively higher price compared to the uncertain risky future costs of conventional power.

In its 2008 edition of World Energy Outlook, the IEA revised its assumptions on both fuel prices and power plant construction cost. Consequently, it increased its estimates for new-build cost. For the European Union, it also assumed that a carbon price of $30 per tonne of CO2 adds $30/MWh to the generating cost of coal and $15/MWh to the generating cost of gas CCGT plants. It shows that the IEA expects new wind power capacity to be cheaper than coal and gas in 2015 and 2030.

2. The price of wind energy

The price of wind energy is different from the cost of wind energy described above. The price depends very much on the institutional setting in which wind energy is delivered. This is a key element to include in any debate about the price or cost of wind energy, and it is essential in order to allow for a proper comparison of costs and prices with other forms of power generation. In this report we distinguish between the production costs of wind, and the price of wind, that is, what a future owner of a wind turbine will be able to bid per kWh in a power purchasing contract tender – or what he would be willing to accept as a fi xed-price, fixed premium or indexed-price offer from an electricity buyer.

There is thus not a single price for wind-generated electricity. The price that a wind turbine owner asks for obviously depends on the costs he has to meet in order to make his delivery, and the risks he has to carry (or insure) in order to fulfi l his contract. Wind power may be sold on long-term contracts with a contract term (duration) of 15-25 years, depending on the preferences of buyers and sellers. Generally speaking, wind turbine owners prefer long-term contracts, since this minimises their investment risks, given that most of their costs are fi xed costs, which are known at the time of the commissioning of the wind turbines.

Compared to traditional fossil-fuel fired thermal power plant, generation from wind (or hydro) plants gives buyers a unique opportunity to sign long-term power purchasing contracts with fixed or largely predictable, general price level indexed prices. This benefit of wind power may or may not be taken into account by the actors on the electrical power market, depending on institutional circumstances in the jurisdiction.

Governments around the world regulate electricity markets heavily, either directly or through nominally independent energy regulators, which interpret more general energy laws. This is true whether we consider jurisdictions with classical electricity monopolies or newer market structures with ‘unbundling’ of transmission and distribution grids from wholesale and retail electricity sales, allowing (some) competition in power generation and in retail sales of electricity. These newer market structures are often somewhat inaccurately referred to as ‘deregulated’ markets, but public regulation is necessary for more than just controlling monopolies (such as the natural monopolies of power transmission and distribution grids) and preventing them from exploiting their market position. Regulation is also necessary to create efficient market mechanisms, e.g. markets for balancing and regulating power. Hence, liberalised or deregulated markets are no less regulated (and should be no less regulated) than classical monopolies, just as stock markets are (and should be) strongly regulated.

As a new and capital-intensive technology, wind energy faces a double challenge in this situation of regulatory flux. Firstly, existing market rules and technical regulations were made to accommodate conventional generating technologies. Secondly, regulatory certainty and stability are economically more important for capital-intensive technologies with a long lifespan than for conventional fuel-intensive generating technologies.

Unregulated markets will not automatically ensure that goods or services are produced or distributed effi ciently or that goods are of a socially acceptable quality. Likewise, unregulated markets do not ensure that production occurs in socially and environmentally acceptable ways. Market regulation is therefore present in all markets and is a cornerstone of public policy. As long as conventional generating technologies pay nowhere near the real social (pollution) cost of their activities, there are thus strong economic efficiency arguments for creating market regulations for renewable energy, which attribute value to the environmental benefi ts of their use. Although the economically most efficient method would theoretically be to use the polluter pays principle to its full extent – in other words, to let all forms of energy use bear their respective pollution costs in the form of a pollution tax – politicians have generally opted for narrower, secondbest solutions. In addition to some minor support to research, development and demonstration projects– and in some cases various investment tax credit or tax deduction schemes – most jurisdictions have opted to support the use of renewable energy through regulating either price or quantity of electricity from renewable sources.

3. Grid, system integration and markets

Introducing signifi cant amounts of wind energy into the power system entails a series of economic impacts -both positive and negative. At the power system level, two main aspects determine wind energy integration costs: balancing needs and grid infrastructure. It is important to acknowledge that these costs also apply to other generating technologies, but not necessarily at the same level. The additional balancing cost in a power system arises from the inherently variable nature of wind power, requiring changes in the confi guration, scheduling and operation of other generators to deal with unpredicted deviations between supply and demand. This report demonstrates that there is sufficient evidence available from national studies to make a good estimate of such costs, and that they are fairly low in comparison with the generation costs of wind energy and with the overall balancing costs of the power system.

Network upgrades are necessary for a number of reasons. Additional transmission lines and capacity need to be provided to reach and connect present and future wind farm sites and to transport power flows in the transmission and distribution networks. These flows result both from an increasing demand and trade of electricity and from the rise of wind power. At significant levels of wind energy penetration, depending on the technical characteristics of the wind projects and trade flows, the networks must be adapted to improve voltage management. Furthermore, the limited interconnection capacity often means the benefi ts coming from the widespread, omnipresent nature of wind, other renewable energy sources and electricity trade in general are lost. In this respect, any infrastructure improvement will bring multiple benefits to the whole system, and therefore its cost should not be allocated only to wind power generation.

Second to second or minute to minute variations in wind energy production are rarely a problem for installing wind power in the grid, since these variations will largely be cancelled out by the other turbines in the grid. Wind turbine energy production may, however, vary from hour to hour, just as electricity demand from electricity costumers will vary from hour to hour. In both cases this means that other generators on the grid have to provide power at short notice to balance supply and demand on the grid.

Studies of the Nordic power market, NordPool, show that the cost of integrating variable wind power in Denmark is, on average, approximately 0.3-0.4 c€/kWh of wind power generated, at the current level of 20% electricity from wind power and under the existing transmission and market conditions. These costs are completely in line with experiences in other countries. The cost of providing this balancing service depends both on the type of other generating equipment available on the grid and on the predictability of the variation in net electricity demand, that is demand variations minus wind power generation. The more predictable the net balancing needs, the easier it will be to schedule the use of balancing power plants and the easier it will be to use the least expensive units to provide the balancing service (that is, to regulate generation up and down at short notice). Wind generation can be very reliably forecast a few hours ahead, and the scheduling process can be eased and balancing costs lowered.

At wind energy penetrations of up to 20% of electricity demand, system operating costs increase by about 1-4 €/MWh of wind generation. This is typically 5-10% or less of the wholesale value of wind energy. Balancing costs increase on a linear basis with wind power penetration; the absolute values are moderate and always less than 4 €/MWh at 20% level (more often in the range below 2 €/MWh). Large balancing areas offer the benefi ts of lower variability. They also help decrease the forecast errors of wind power, and thus reduce the amount of unforeseen imbalance. Large areas favour the pooling of more cost-effective balancing resources. In this respect, the regional aggregation of power markets in Europe is expected to improve the economics of wind energy integration. Additional and better interconnection is the key to enlarging balancing areas. Certainly, improved interconnection will bring benefits for wind power integration. These are quantifi ed by studies such as TradeWind.

The consequences of adding more wind power into the grid have been analysed in several European countries. The national studies quantify grid extension measures and the associated costs caused by additional generation and demand in general, and by wind power production. The analyses are based on load fl ow simulations of the corresponding national transmission and distribution grids and take into account different scenarios for wind energy integration using existing, planned and future sites. It appears that additional grid extension/reinforcement costs are in the range of 0.1 to 5€/MWh – typically around 10% of wind energy generation costs for a 30% wind energy share. Grid infrastructure costs (per MWh of wind energy) appear to be around the same level as additional balancing costs for reserves in the system to accommodate wind power.

Wind power is expected to infl uence prices on the power market in two ways: Wind power normally has a low marginal cost (zero fuel costs) and therefore enters near the bottom of the supply curve. In general, the price of power is expected to be lower during periods with high wind than in periods with low wind. This is known as the ‘merit order effect’. As mentioned, there may be congestions in power transmission, especially during periods with high wind power generation. Thus, if the available transmission capacity cannot cope with the required power export, the supply area is separated from the rest of the power market and constitutes its own pricing area. With an excess supply of power in this area, conventional power plants have to reduce their production, since it is generally not economically or environmentally desirable to limit the power production of wind. In most cases, this will lead to a lower power price in this sub-market.

However, the impact of wind power depends on the time of the day. If there is plenty of wind power at midday, during the peak power demand, most of the available generation will be used. But if there is plenty of wind-produced electricity during the night, when power demand is low and most power is produced on base load plants, we are at the fl at part of the supply curve and consequently the impact of wind power on the spot price is low.

When wind power reduces the spot power price, it has a signifi cant influence on the price of power for consumers. When the spot price is lowered, this is beneficial to all power consumers, since the reduction in price applies to all electricity traded – not only to electricity generated by wind power. In general in 2004-2007, the cost of power to the consumer (excluding transmission and distribution tariffs, taxes and VAT) would have been approximately 4-12% higher in Denmark if wind power had not contributed to power production. Wind power’s strongest impact is estimated to have been for west Denmark, due to the high penetration of wind power in this area. In 2007, this adds up to approximately 0.5 c€kWh saved by power consumers, as a result of wind power lowering electricity prices. Although wind power in the Nordic countries is mainly established in Denmark, all Nordic power consumers benefit financially due to the presence of Danish wind power on the market.

4. Energy policy and economic risk

Industrialised countries – and European countries in particular – are becoming increasingly dependent on fossil fuel imports, more often than not from areas which are potentially politically unstable. At the same time global energy demand is increasing rapidly, and climate change requires urgent action. In this situation it seems likely that fuel and carbon price increases and volatility will become major risk factors not just for the cost of power generation, but also for the economy as a whole. In a global context, Europe stands out as an energy intensive region heavily reliant on imports (54% of the EU’s primary demand). The EU’s largest remaining oil and gas reserves in the North Sea have already peaked. The European Commission reckons that, without a change in direction, this reliance will be as high as 65% by 2030. Gas imports in particular are expected to increase from 57% today to 84% in 2030, and oil imports from 82% to 93%. The European Commission estimates that the EU countries’ energy import bill was €50 billion in 2008, equal to around €00 for every EU citizen.

In turn, the International Energy Agency predicts that global demand for oil will go up by 41% in 2030, stating that “the ability and willingness of major oil and gas producers to step up investment in order to meet rising global demand are particularly uncertain”. Even if the major oil and gas producers were able to match the rising global demand, considerable doubt exists concerning the actual level of accessible remaining reserves.

The use of fossil fuel fired power plants exposes electricity consumers and society as a whole to the risk of volatile and unpredictable fuel prices. To make matters worse, government energy planners, the European Commission and the IEA have consistently been using energy models and cost-of-energy (COE) calculation methods that do not properly account for fuel and carbon price risks.

The oil and gas price hikes of the supply crises of the 1970s had dramatic effects on the world economy, creating infl ation and stifl ing economic growth for a decade. Fossil fuel prices, which are variable and hard to predict, pose a threat to economic development. The vulnerability of an economic system to oil price was empirically formulated by J.K. Hamilton in 1983 and relevant literature refers to it as the “oil-GDP effect”.

The higher capital costs of wind are offset by very low variable costs, due to the fact that fuel is free, but the investor will only recover those after several years. This is why regulatory stability is so important for the sector.

5. A new model for comparing power generating cost – accounting for fuel and carbon price risk

Wind, solar and hydropower differ from conventional thermal power plant in that most of the costs of owning and operating the plant are known in advance with great certainty. These are capital-intensive technologies – O&M costs are relatively low compared to thermal power plants since the energy input is free. Capital costs (interest and depreciation) are known as soon as the plant is built and financed, so we can be certain of the future costs. Wind power may thus be classifi ed as a low-risk technology when we deal with cost assessments.

The situation for thermal power plants is different: These technologies are expense-intensive technologies – in other words, they have high O&M costs, with by far the largest item being the fuel fi ll. Future fuel prices, however, are not just uncertain – they are highly unpredictable. This distinction between uncertainty and unpredictability is essential. If fuel prices were just uncertain, you could probably buy insurance for your monthly fuel bill (much as you can insure your wind generation if the insurance company knows the likely mean generation on an annual and seasonal basis). Since there is a world market for gas and oil, most of the insurance for predictable, but (short-term) uncertain fuel prices could probably be bought in a world-wide fi nancial futures market for oil and gas prices, where speculators would actively be at work and thus help stabilise prices. But this is not how the real world looks.

In the real world, you can neither simply nor safely buy a fossil-fuel contract for delivery 15 or 20 years ahead, the long-term futures market for fuels does not exist and it never will; the risks are too great for both parties to sign such a contract because fuel prices are not just uncertain – they are too unpredictable. But you cannot sensibly deal with real risk in an economic calculation by assuming it does not exist. The unpleasant corollary of this is that the ‘engineering-economics cost calculations’ (levelised-cost approaches), widely used by governments and international organisations, simply do not make sense because future fuel prices – just like stock prices – are both uncertain and highly unpredictable.

Likewise, investors in power plants – or society at large – should be equally rational and choose to invest in power plants with a possibly lower, but predictable rate of return rather than investing in power plant with a possibly higher, but unpredictable rate of return. The way to analyse this in financial economics is to use different discount rates depending on the risks involved. Unpredictable income has to be discounted at a higher rate than predictable income, just as for fi nancial markets. What does this analysis tell us about the way the IEA, governments and the European Commission currently calculate the cost of energy from different sources? It tells us that when these institutions apply a single rate of discount to all future expenditure, they pretend that fuel prices are riskless and predictable.

Fuel prices are thus discounted too heavily, which underestimates their cost and overstates their desirability relative to less risky capital expenditure. In other words, current calculation practice favours conventional, expenditure- intensive fuel-based power generation over capital-intensive, zero carbon and zero fuel-price risk power generation from renewables such as wind power.

Traditional, engineering-economics cost models were first conceived a century ago, and have been discarded in other industries (because of their bias towards lower-cost but high risk expense-intensive technology. In energy models, they continue to be applied widely. In the case of electricity cost estimates, current models will almost always imply that risky fossil alternatives are more cost-effective than cost-certain renewables.

This is roughly analogous to telling investors that high-yielding but risky “junk bonds” or stocks are categorically a better investment than lower yielding but more secure and predictable government bonds. If our power supply consisted of only oil, gas and coal technology, the engineering cost approach would not be too much of a problem. This was true for most of the last century but is no longer the case. Today, energy planners can choose from a broad variety of resource options that ranges from traditional, risky fossil alternatives to low-risk, passive, capital-intensive wind with low fuel and operating cost risks. Current energy models assumes away the fuel cost risk by using different discount rates (sensitivity analysis).

But as explained above, this method does not solve the problem of comparing different technologies with different fuel requirements – or no fuels, as it is the case for wind energy. Rather than using different risk levels, and applying those to all technologies, the IEA should use differentiated discount rates for the various technologies. In contrast to the previous sections, this section describes a market-based or fi nancial economics approach to COE estimation that differs from the traditional engineering-economics approach. It is based on groundbreaking work by the late Shimon Awerbuch. He argued that comparing the costs of wind and other technologies using the same discount rate for each gives meaningless results. In order to make meaningful COE comparisons we must estimate a reasonably accurate discount rate for generating cost outlays – fuel and O&M. Although each of these cost streams requires its own discount rate, fuel outlays require special attention since they are much larger than the other generating costs on a risk-adjusted basis.

By applying different methods for estimating the discount rates for fossil fuel technologies we find that the present value cost of fossil fuel expenditure is considerably greater than those obtained by the IEA and others who use arbitrary (nominal) discount rates in the range of 8% to as much as 13%.

In the IEA 2005 report “Projected costs of generating capacity, 2005”, a typical natural gas power plant is assumed to have fuel costs of $2,967 at a 10% discount rate, equivalent to $0.049 per kWh (around 3.9 c€kWh ). However, if a historical fuel price risk methodology is used instead, fuel costs go up to $8,018, equal to $0.090 per kWh (approx. 7.2 c€kWh). With an assumed no-cost 40 Year Fuel purchase contract, the figures would have been $7,115 or $0.081 per kWh (6.48 c€kWh).

Something similar happens for coal plants, which are also covered in the IEA report. In the central case, with a discount rate of 10%, the fuel costs of a coal power station are equal to $1,234 or $0.040 per kWh (around 3.2 c€/kWh). If the historical fuel price risk methodology is preferred, the fuel costs peak at $5,324 or $0.083 per kWh (6.64 c€/kWh). Finally, when the no-cost 40 Year Fuel purchase contract is assumed, the figures appear as $3,709 and $0.066 per kWh respectively (approx. 5.28 c€/kWh).

In both cases the fuel costs and subsequently the total generating costs more than double when differentiated discount rates are assumed. Wind energy cost remains unchanged because the technology carries no fuel price risk. It should be noted that the onshore wind energy cost calculated above are based on IEA methodology, which gives a wind energy generating cost of 5.3 c€/kWh. In Chapter 2 of the report, we find that the levelised cost of onshore wind energy range between 6 c€/kWh at a discount rate of 5% to 8 c€/kWh at a discount rate of 10% at a medium wind site.

Shimon Awerbuch carried out this analysis based on an IEA Report on electricity generating cost published in 2005 when the average IEA crude oil import price averaged $51/barrel. Results would obviously be very different if fuel prices were equivalent to the $150/barrel reached in mid 2008. Although only an example, the figures reflect how the relative position of wind energy vis-a-vis other technologies will substantially vary if a different – and more rational – COE estimate is used. Wind energy would appear even more cost competitive if carbon price risk had been included in the analysis.