Re technologies cost_analysis-wind_power

IRENA
RENEWABLE ENERGY TECHNOLOGIES: COST ANALYSIS SERIES
Issue 5/5
Wind Power
June 2012
International Renewable Energy Agency
IRENA woRkINggg pppApER
Volume 1: Power Sector

Copyright (c) IRENA 2012
Unless otherwise indicated, material in this publication may be used freely, shared or reprinted,
but acknowledgement is requested.
About IRENA
The International Renewable Energy Agency (IRENA) is an intergovernmental organisation dedicated
to renewable energy.
In accordance with its Statute, IRENA's objective is to "promote the widespread and increased
adoption and the sustainable use of all forms of renewable energy". This concerns all forms of
energy produced from renewable sources in a sustainable manner and includes bioenergy,
geothermal energy, hydropower, ocean, solar and wind energy.
As of May 2012, the membership of IRENA comprised 158 States and the European Union (EU), out
of which 94 States and the EU have ratified the Statute.
Acknowledgement
This paper was prepared by the IRENA Secretariat. The paper benefitted from an internal IRENA
review, as well as valuable comments and guidance from Stefan Gsänger (WWEA), Steve Sawyer
(GWEC) and Cassia Simons Januario (VESTAS).
For further information or to provide feedback, please contact Michael Taylor, IRENA Innovation
and Technology Centre, Robert-Schuman-Platz 3, 53175 Bonn, Germany; MTaylor@irena.org.
This working paper is available for download from www.irena.org/Publications
Disclaimer
The designations employed and the presentation of materials herein do not imply the expression
of any opinion whatsoever on the part of the Secretariat of the International Renewable Energy
Agency concerning the legal status of any country, territory, city or area or of its authorities, or con-cerning
the delimitation of its frontiers or boundaries. The term “country” as used in this material
also refers, as appropriate, to territories or areas.

Preface
Renewable power generation can help countries meet their sustainable development
goals through provision of access to clean, secure, reliable and affordable energy.
Renewable energy has gone mainstream, accounting for the majority of capacity
additions in power generation today. Tens of gigawatts of wind, hydropower and
solar photovoltaic capacity are installed worldwide every year in a renewable energy
market that is worth more than a hundred billion USD annually. Other renewable power
technology markets are also emerging. Recent years have seen dramatic reductions in
renewable energy technologies’ costs as a result of R&D and accelerated deployment.
Yet policy-makers are often not aware of the latest cost data.
International Renewable Energy Agency (IRENA) Member Countries have asked for
better, objective cost data for renewable energy technologies. This working paper aims
to serve that need and is part of a set of five reports on wind, biomass, hydropower,
concentrating solar power and solar pholtovoltaics that address the current costs of
these key renewable power technology options. The reports provide valuable insights
into the current state of deployment, types of technologies available and their costs and
performance. The analysis is based on a range of data sources with the objective of
developing a uniform dataset that supports comparison across technologies of different
cost indicators - equipment, project and levelised cost of electricity – and allows for
technology and cost trends, as well as their variability to be assessed.
The papers are not a detailed financial analysis of project economics. However, they do
provide simple, clear metrics based on up-to-date and reliable information which can be
used to evaluate the costs and performance of different renewable power generation
technologies. These reports help to inform the current debate about renewable power
generation and assist governments and key decision makers to make informed
decisions on policy and investment.
The dataset used in these papers will be augmented over time with new project cost
data collected from IRENA Member Countries. The combined data will be the basis for
forthcoming IRENA publications and toolkits to assist countries with renewable energy
policy development and planning. Therefore, we welcome your feedback on the data
and analysis presented in these papers, and we hope that they help you in your policy,
planning and investment decisions.
Dolf Gielen
Director, Innovation and Technology

Contents
KEY FINDINGS i
LIST OF TABLES AND FIGURES ii
1. INTRODUCTION 1
1.1 Different measures of cost and data limitations
1.2 Levelised cost of electricity generation
2. WIND POWER TECHNOLOGIES AND RESOURCES 4
2.1 Wind turbine and wind farm designs
2.1.1 Onshore wind power technologies
2.1.2 Offshore wind power technologies
2.1.3 Small wind turbines
2.2 The global wind energy resource
3. GLOBAL WIND POWER MARKET TRENDS 12
3.1 Total installed capacity
3.2 Annual capacity additions
3.3 Future projections of capacity growth
4. CURRENT COST OF WIND POWER 18
4.1. A breakdown of the installed capital cost for wind
4.2 Total installed capital costs of wind power systems, 1980 to 2010
4.2.1 Wind turbine costs
4.2.2 Grid connection costs
4.2.3 Civil works and construction costs
4.3 Operations and maintenance costs
4.4 Total installed cost of wind power systems
5. WIND POWER COST REDUCTION POTENTIALS 35
5.1 Cost reduction potential by source
5.2 Overall cost reduction potentials
6. LEVELISED COST OF ELECTRICITY FROM WIND POWER 42
6.1 Cost structure of large-scale wind farms
6.1.1 The capital costs of onshore and offshore wind farms
6.1.2 O&M costs of onshore and offshore wind farms
6.2 Recent estimates of the LCOE of onshore and offshore wind
6.3 LCOE estimates for 2011 to 2015
REFERENCES 52
ACRONYMS 55

Key findings
1. Installed costs in 2010 for onshore wind farms were as low as USD 1 300 to USD 1 400/kW in China
and Denmark, but typically ranged between USD 1 800/kW and USD 2 200/kW in most other major
markets. Preliminary data for the United States in 2011 suggests that wind turbine costs have peaked
and that total costs could have declined to USD€2 000/kW for the full year (i.e. a reduction of USD
150/kW compared to 2010). Wind turbines account for 64% to 84% of total installed costs onshore,
with grid connection costs, construction costs, and other costs making up the balance. Oˆshore
wind farms are more expensive and cost USD 4 000 to USD 4 500/kW, with the wind turbines
accounting for 44% to 50% of the total cost.
TABLE 1: TYPICAL NEW WIND FARM COSTS AND PERFORMANCE IN 2010
Installed cost
(2010 USD/kW)
Capacity factor
(%)
Operations and
maintenance (USD/kWh)
LCOE* (USD/kWh)
Onshore
China/India 1 300 to 1 450 20 to 30 n.a. 0.06 to 0.11
Europe 1 850 to 2 100 25 to 35 0.013 to 0.025 0.08 to 0.14
North America 2 000 to 2 200 30 to 45 0.005 to 0.015 0.07 to 0.11
O
shore
Europe 4 000 to 4 500 40 to 50 0.027 to 0.048 0.14 to 0.19
* Assumes a 10% cost of capital
2. Operations and maintenance costs (O&M) can account for between 11% and 30% of an onshore wind
projects levelised cost of electricity (LCOE). O&M costs for onshore wind farms in major wind markets
averages between USD 0.01/kWh and USD 0.025/kWh. The O&M costs of oˆshore wind farms are
higher due to the di’culties posed by the oˆshore environment and can be between USD 0.027 and
USD 0.048/kWh. Cost reduction opportunities towards best practice levels exist for onshore wind
farms, while experience oˆshore should help to reduce costs over time, but they will always be higher
than onshore.
3. The levelised cost of electricity from wind varies depending on the wind resource and project costs,
but at good wind sites can be very competitive. The LCOE of typical new onshore wind farms in
2010 assuming a cost of capital of 10% was between USD 0.06 to USD 0.14/kWh. The higher capital
costs oˆshore are somewhat oˆset by the higher capacity factors achieved, resulting in the LCOE of
an oˆshore wind farm being between USD 0.13 and USD 0.19/kWh assuming a 10% cost of capital.
4. The potential for renewed cost reductions is good, as supply bottlenecks have been removed and
increased competition among suppliers will put downward pressure on prices in the next few years.
Assuming that capital costs onshore decline by 7% to 10% by 2015, and O&M costs trend towards
best practice, the LCOE of onshore wind could decline by 6% to 9%. The short-term cost reduction
potential for wind is more uncertain, but the LCOE of oˆshore wind could decline by between 8%
and 10% by 2015.
5. In the medium-to long-term, reductions in capital costs in the order of 10% to 30% could be
achievable from learning-by-doing, improvements in the supply chain, increased manufacturing
economies of scale, competition and more investment in R&D.
Cost Analysis of Wind Power i

List of tables
Table 2.1: Impact of turbine sizes, rotor diameters and hub heights on annual production 5
Table 2.2: offshore wind turbine foundation options 8
Table 4.1: Comparison of capital cost breakdown for typical onshore and offshore wind power systems in developed countries, 2011 19
Table 4.2: average wind turbine prices (real) by country, 2006 to 2010 22
Table 4.3: o&M costs for onshore wind projects 28
Table 4.4: onshore wind power system installed costs for selected countries, 2003 to 2010 29
Table 4.5: Capital cost structure of offshore wind power systems, 2010 34
Table 5.1: Projected capital costs for small-scale wind farms (16 MW) with 2 MW turbines in the united Kingdom, 2011 to 2040 36
Table 5.2: Summary of cost reduction opportunities for offshore wind 40
Table 5.3: Different estimates of the potential for cost reductions in the installed cost of onshore wind, 2011 to 2050 40
Table 6.1: total installed costs for onshore wind farms in China/India, Europe and North america, 2010, 2011 and 2015 43
Table 6.2: LCoE of wind at different capacity factors and discount rates 50
List of figures
Figure 1.1: renewable power generation cost indicators and boundaries 2
Figure 2.1: Growth in the size of wind turbines since 1985 6
Figure 2.2: World wind resource map 11
Figure 3.1: Global installed wind power capacity, 1996 to 2011 12
Figure 3.2: the top ten countries by installed wind capacity, end-2011 13
Figure 3.3: Global new wind power capacity additions, 1996 to 2011 14
Figure 3.4: top ten countries by new wind power capacity additions in 2011 15
Figure 3.5: Wind power projects partially commissioned, under construction or with financing secured (84.8 GW). 16
Figure 3.6: Projected growth in global wind power annual capacity additions and cumulative installed capacity, 2010 to 2015 17
Figure 4.1: Capital cost breakdown for a typical onshore wind power system and turbine 18
Figure 4.2: Wind turbine price index by delivery date, 2004 to 2012 20
Figure 4.3: reported wind turbine transaction prices in the united States, 1997 to 2012 21
Figure 4.4: Wind turbine cost breakdown (5 MW offshore wind turbine) 23
Figure 4.5: Wind turbine cost in selected countries, 2008 and 2010 24
Figure 4.6: Copper and steel prices, 1990 to 2010 25
Figure 4.7: o&M costs for wind power projects in the united States, 1980 to 2008 26
Figure 4.8: o&M costs in the united States by number of years since start of commercial operation 27
Figure 4.9: onshore wind power system installed cost for selected countries, 2007 to 2010 30
Figure 4.10: Installed cost of wind power projects in the united States, 1982 to 2011 31
Figure 4.11: average installed cost of wind power projects in the united States by project size, 2009 and 2010 31
Figure 4.12: Installed cost of wind power projects in the united States by turbine size: 2009 and 2010 32
Figure 4.13: the capacity-weighted average capacity factors for projects in the united States, 1999 to 2010 32
Figure 4.14: Estimates of offshore wind power capital costs 33
Figure 5.1: Historical learning rate for wind turbines, 1984 to 2010 36
Figure 6.1: the economics of wind systems 42
Figure 6.2: Capital cost breakdowns for typical onshore and offshore wind systems 43
Figure 6.3: Share of o&M in the total LCoE of wind power in seven countries 44
Figure 6.4: Wind power prices in the united States by start year, 1998/1999 to 2010 45
Figure 6.5: Wind auction prices in brazil, 2009 to 2011 46
Figure 6.6: Wind power LCoE trends for period from Q2 2009 to Q2 2011 47
Figure 6.7: the LCoE of wind for typical European onshore wind farms, 2011 to 2015 48
Figure 6.8: the LCoE of wind for typical North american onshore wind farms, 2011 to 2015 49
Figure 6.9: the LCoE of wind for typical offshore wind farms, 2011 to 2015 51
ii Cost Analysis of Wind Power

Renewable energy technologies can help countries meet their policy goals for secure, reliable and affordable
energy to expand electricity access and promote development. This paper is part of a series on the cost
and performance of renewable energy technologies produced by IRENA. The goal of these papers is to assist
government decision-making and ensure that governments have access to up-to-date and reliable information on
the costs and performance of renewable energy technologies.
1.1 DIFFErENt MEaSurES oF CoSt
aND Data LIMItatIoNS
Cost can be measured in a number of different ways, and
each way of accounting for the cost of power generation
brings its own insights. The costs that can be examined
include equipment costs (e.g. wind turbines, PV modules,
solar reflectors, etc.), financing costs, total installed cost,
fixed and variable operating and maintenance costs (O&M),
fuel costs, and the levelised cost of energy (LCOE).
The analysis of costs can be very detailed, but for
comparison purposes and transparency, the approach
used here is a simplified version. This allows greater
scrutiny of the underlying data and assumptions,
improving transparency and the confidence in the
analysis, as well as facilitating the comparison of costs
by country or region for the same technologies in order
to identify what are the key drivers in any differences.
The three indicators that have been selected are:
»» Equipment cost (factory gate FOB and
»» Total installed project cost, including
fixed financing costs2; and
»» The levelised cost of electricity LCOE.
The analysis in this paper focuses on estimating the
cost of wind energy from the perspective of a private
investor, whether they are a state-owned electricity
generation utility, an independent power producer, or
Cost Analysis of Wind Power 1
1. Introduction
Without access to reliable information on the relative
costs and benefits of renewable energy technologies,
it is difficult, if not impossible, for governments to
arrive at an accurate assessment of which renewable
energy technologies are the most appropriate for their
particular circumstances. These papers fill a significant
gap in information availability, because there is a lack
of accurate, comparable, reliable and up-to-date data
on the costs and performance of renewable energy
technologies. The rapid growth in installed capacity
of renewable energy technologies and the associated
cost reductions mean that even data one or two years
old can significantly overestimate the cost of electricity
from renewable energy technologies. There is also a
significant amount of perceived knowledge about the
cost and performance of renewable power generation
technologies that is not accurate or is misleading.
Conventions on how to calculate cost can influence the
outcome significantly and it is imperative that these are
clearly documented.
The absence of accurate and reliable data on the cost
and performance of renewable power generation
technologies is a significant barrier to the uptake of
these technologies. Providing this information will help
governments, policy-makers, investors and utilities make
informed decisions about the role renewable energy can
play in their power generation mix. This paper examines
the fixed and variable cost components of wind power,
by country and region and provides estimates of the
levelised cost of electricity from wind power given a
number of key assumptions. This up-to-date analysis of
the costs of generating electricity from wind will allow a
fair comparison with other generating technologies.1
delivered at site CIF);
1 IRENA, through its other work programmes, is also looking at the costs and benefits, as well as the macroeconomic impacts, of renewable power
generation technologies. See WWW.IRENA.ORG for further details.
2 Banks or other financial institutions will often charge a fee, usually a percentage of the total funds sought, to arrange the debt financing of a project.
These costs are often reported separately under project development costs.

an individual or community looking to invest in small-scale
renewables (Figure 1.1). The analysis is a pure cost
analysis, not a financial one, and excludes the impact of
government incentives or subsidies, taxation, system-balancing
costs associated with variable renewables,
and any system-wide cost savings from the merit
order eect.3 Similarly, the analysis doesn’t take into
account any CO2 pricing, nor the benefits of renewables
in reducing other externalities (e.g. reduced local air
pollution, contamination of natural environments, etc.).
Similarly, the benefits of renewables being insulated
from volatile fossil fuel prices have not been quantified.
These issues and others are important, but are covered
by other programmes of work at IRENA.
It is important to include clear definitions of the
technology categories, where this is relevant, to ensure
that cost comparisons are robust and provide useful
insights (e.g. o-shore wind vs. onshore wind PV).
Similarly, it is important to dierentiate between the
functionality and/or qualities of the renewable power
generation technologies being investigated. It is
important to ensure that system boundaries for costs
are clearly set and that the available data are directly
comparable. Other issues can also be important, such
as cost allocation rules for combined heat and power
plants, and grid connection costs and rules.
Factory gate
Equipment
Transport cost
Import levies
The data used for the comparisons in this paper come
from a variety of sources, such as business journals,
industry associations, consultancies, governments,
auctions and tenders. Every eort has been made to
ensure that these data are directly comparable and are for
the same system boundaries. Where this is not the case,
the data have been corrected to a common basis using
the best available data or assumptions. It is planned that
this data will be complemented by detailed surveys of real
world project data in forthcoming work by the agency.
An important point is that, although this paper tries to
examine costs, strictly speaking, the data available are
actually prices, and not even true market average prices,
but price indicators. The dierence between costs and
prices is determined by the amount above, or below, the
normal profit that would be seen in a competitive market.
The rapid growth of renewables markets from a small base
means that the market for renewable power generation
technologies is rarely well-balanced. As a result, prices
can rise significantly above costs in the short-term if
supply is not expanding as fast as demand, while in times
of excess supply, losses can occur and prices may be
below production costs. This makes analysing the cost
of renewable power generation technologies challenging
and every eort is made to indicate whether current
equipment costs are above or below their long-term trend.
FIGURE 1.1: RENEWABLE POWER GENERATION COST INDICATORS AND BOUNDARIES
3 See EWEA, Wind Energy and Electricity Prices, April 2010 for a discussion.
2 Cost Analysis of Wind Power
Project development
Site preparation
Grid connection
Working capital
Auxiliary equipment
Non-commercial cost
Operation &
Maintenance
Cost of finance
Resource quality
Capacity factor
Life span
Levelized cost of electricity
(Discounted lifetime cost
divided by discounted
lifetime generation)
On site
Equipment
Project cost LCOE

technologies. The differences in LCOE can be attributed
to project and technology performance, not differing
methodologies. More detailed LCOE analysis may
result in more “accurate” absolute values, but results
in a significantly higher overhead in terms of the
granularity of assumptions required and risks reducing
transparency. More detailed methodologies can often
give the impression of greater accuracy, but when it
is not possible to robustly populate the model with
assumptions, or to differentiate assumptions based on
real world data, then the supposed “accuracy” of the
approach can be misleading.
The formula used for calculating the LCOE of renewable
energy technologies is:
Σ
n
t = 1
Σ
It + Mt + Ft
(1+r)t
n
t = 1
Et
(1+r)t
LCOE =
Where:
LCOE = the average lifetime levelised cost of electricity
generation;
It = investment expenditures in the year t;
Mt = operations and maintenance expenditures in the
year t;
Ft = fuel expenditures in the year t;
Et = electricity generation in the year t;
r = discount rate; and
n = economic life of the system.
All costs presented in this paper are real 2010 USD
unless otherwise stated;5 that is to say, after inflation has
been taken into account.6 The discount rate used in the
analysis, unless otherwise stated, is 10% for all projects
and technologies.
As already mentioned, although different cost measures
are useful in different situations, the LCOE of renewable
energy technologies is a widely used measure by
which renewable energy technologies can be evaluated
for modelling or policy development. Similarly, more
detailed DCF approaches taking into account taxation,
subsidies and other incentives are used by renewable
energy project developers to assess the profitability of
real world projects.
The cost of equipment at the factory gate is often available
from market surveys or from other sources. A key difficulty
is often reconciling different sources of data to identify
why data for the same period differ. The balance of capital
costs in total project costs tends to vary even more widely
than power generation equipment costs, as it is often
based on significant local content, which depends on the
cost structure where the project is being developed. Total
installed costs can therefore vary significantly by project,
country and region, depending on a wide range of factors.
1.2 LeveLised cost
of eLectricity generation
The LCOE is the price of electricity required for a project
where revenues would equal costs, including making
a return on the capital invested equal to the discount
rate. An electricity price above this would yield a greater
return on capital, while a price below it would yielder a
lower return on capital, or even a loss.
The LCOE of renewable energy technologies varies by
technology, country and project, based on the renewable
energy resource, capital and operating costs, and the
efficiency/performance of the technology. The approach
used in the analysis presented here is based on a simple
discounted cash flow (DCF) analysis.4 This method of
calculating the cost of renewable energy technologies is
based on discounting financial flows (annual, quarterly
or monthly) to a common basis, taking into consideration
the time value of money. Given the capital intensive
nature of most renewable power generation technologies
and the fact that fuel costs are low, or often zero, the
weighted average cost of capital (WACC), also referred
to as the discount rate in this report, used to evaluate the
project has a critical impact on the LCOE.
There are many potential trade-offs to be considered
when developing an LCOE modelling approach. The
approach taken here is relatively simple, given the fact
that the model needs to be applied to a wide range
of technologies in different countries and regions.
However, this has the additional advantage of making
the analysis transparent, easy to understand and
allows clear comparisons of the LCOE of individual
technologies across countries and regions, and between
4 Including the impacts of subsidies, taxation and other factors that impact the financial viability of an individual project would lead to different results.
5 Exchange rate fluctuations can have a significant impact on project costs depending on the level of local content. In an ideal world the local and
imported cost components could be tracked separately and trends in each followed without the “noise” created by exchange rate fluctuations.
6 An analysis based on nominal values with specific inflation assumptions for each of the cost components is beyond the scope of this analysis. Project
developers will develop their own specific cash-flow models to identify the profitability of a project from their perspective.

2. Wind power technologies
and resources
Wind power technologies transform the kinetic energy of the wind into useful mechanical power. The kinetic
energy of the air flow provides the motive force that turns the wind turbine blades that, via a drive shaft,
provide the mechanical energy to power the generator in the wind turbine.7
Wind and hydro power have been used by man since
antiquity and they are the oldest large-scale source
of power that has been used by mankind. However,
the invention of the steam engine and its wide spread
deployment in the nineteenth century allowed the
industrial revolution to occur by providing cheap, on-demand
mechanical and then electrical energy, with
the possibility of taking advantage of the waste heat
produced as well. Their low cost and the fact they did
not depend on fickle winds or need to be located next
to a convenient water source allowed the great leap
in productivity and incomes that stemmed from the
Industrial Revolution. Their success saw the importance
of wind energy decline dramatically, particularly in the
twentieth century.
The modern era of wind power began in 1979 with
the mass production of wind turbines by Danish
manufacturers Kuriant, Vestas, Nordtank and Bonus.
These early wind turbines typically had small capacities
(10 kW to 30 kW) by today’s standards, but pioneered
the development of the modern wind power industry
that we see today.
The current average size of grid-connected wind turbines
is around 1.16 MW (BTM Consult, 2011), while most new
projects use wind turbines between 2 MW and 3 MW.
Even larger models are available, for instance REPower’s
5 MW wind turbine has been on the market for seven
years. When wind turbines are grouped together, they
are referred to as “wind farms”. Wind farms comprise the
turbines themselves, plus roads for site access, buildings
(if any) and the grid connection point.
Wind power technologies come in a variety of sizes and
styles and can generally be categorised by whether they
are horizontal axis or vertical axis wind turbines (HAWT
and VAWT), and by whether they are located onshore
or offshore. The power generation of wind turbines is
determined by the capacity of the turbine (in kW or
MW), the wind speed, the height of the turbine and the
diameter of the rotors.
Most modern large-scale wind turbines have three blades
rotating around the horizontal axis (the axis of the drive
shaft). These wind turbines account for almost all utility-scale
wind turbines installed. Vertical-axis wind turbines
exist, but they are theoretically less aerodynamically
efficient than horizontal-axis turbines and don’t have a
significant market share.8 In addition to large-scale designs,
there has been renewed interest in small-scale wind
turbines, with some innovative design options developed in
recent years for small-scale vertical-axis turbines.
Horizontal-axis wind turbines can be classified by their
technical characteristics, including:
»» rotor placement (upwind or downwind);
»» the number of blades;
»» the output regulation system for the
generator;
»» the hub connection to the rotor (rigid or
hinged; the so-called “teetering hub”);
»» gearbox design (multi-stage gearbox
with high speed generator; single
stage gearbox with medium speed
generator or direct drive with
synchronous generator);
7 Wind turbine refers to the tower, blades, rotor hub, nacelle and the components housed in the nacelle.
8 There are three vertical-axis wind turbine design concepts: the Gyro-turbine, the Savonius turbine and the Darrieus turbine. Only the Darrieus turbine
has been deployed at any scale (in Denmark in the 1970s). Today, they are used for small scale applications in turbulent environments, like cities. Some
prototypes have been proposed for large-scale offshore applications in order to reduce installation and maintenance costs.

Generator size, MW Rotor, m Hub Height, m Annual production, MWh
3.0 90 80 7 089
3.0 90 90 7 497
3.0 112 94 10 384
1.8 80 80 6 047
»» the rotational speed of the rotor to
maintain a constant frequency (fixed or
controlled by power electronics); and
»» wind turbine capacity.
The turbine size and the type of wind power system
are usually related. Today’s utility-scale wind turbine
generally has three blades, sweeps a diameter of about
80 to 100 metres, has a capacity from 0.5 MW to 3 MW
and is part of a wind farm of between 15 and as many as
150 turbines that are connected to the grid.
Small wind turbines are generally considered to be
those with generation capacities of less than 100 kW.
These smaller turbines can be used to power remote or
off-grid applications such as homes, farms, refuges or
beacons. Intermediate-sized wind power systems (100
kW to 250 kW) can power a village or a cluster of small
enterprises and can be grid-connected or off-grid. These
turbines can be coupled with diesel generators, batteries
and other distributed energy sources for remote use
where there is no access to the grid. Small-scale wind
systems remain a niche application, but it is a market
segment that is growing quickly.9 They are emerging as
an important component of renewable electrification
schemes for rural communities in hybrid off-grid and
mini-grid systems.
The wind speed and electricity production
As wind speed increases, the amount of available energy
increases, following a cubic function. Therefore, capacity
factors rise rapidly as the average mean wind speed
increases. A doubling of wind speed increases power
output of wind turbine by a factor of eight (EWEA,
2009). There is, therefore, a significant incentive to site
wind farms in areas with high average wind speeds. In
addition, the wind generally blows more consistently at
higher speeds at greater heights. For instance, a five-fold
increase in the height of a wind turbine above the
prevailing terrain can result in twice as much wind power.
Air temperature also has an effect, as denser (colder) air
provides more energy. The ”smoothness” of the air is also
important. Turbulent air reduces output and can increase
the loads on the structure and equipment, increasing
materials fatigue, and hence O&M costs for turbines.
The maximum energy than can be harnessed by a wind
turbine is roughly proportionally to the swept area of the
rotor. Blade design and technology developments are
one of the keys to increasing wind turbine capacity and
output. By doubling the rotor diameter, the swept area
and therefore power output is increased by a factor of
four. Table 2.1 presents an example for Denmark of the
impact of different design choices for turbine sizes, rotor
diameters and hub heights.
The advantage of shifting offshore brings not only higher
average mean wind speeds, but also the ability to build
very large turbines with large rotor diameters. Although
this trend is not confined to offshore, the size of wind
turbines installed onshore has also continued to grow.
The average wind turbine size is currently between 2 MW
and 3 MW. Larger turbines provide greater efficiency and
economy of scale, but they are also more complex to
build, transport and deploy.10 An additional consideration
is the cost, as wind towers are usually made of rolled
steel plate. Rising commodity prices during the period
2006-2008 drove increased wind power costs, with the
price of steel tripling between 2005 and its peak in mid-
2008.
Table 2.1: impacT of Turbine sizes, roTor diameTers and hub heighTs on annual producTion
Source: Nielsen, et al., 2010
9 The World Wind Energy Association estimates that the number of installed small wind turbines by end of 2010 was around 665 000 units.
10 As tower height increases, so does the diameter at the base. Once the diameter of the tower exceeds about 4 metres, transportation by road can
became problematic.

15 m ø
’85
.05
’95
1.3
’97
1.6
FIGURE 2.1: GROWTH IN THE SIZE OF WIND TURBINES SINCE 1985
Source: UpWind, 2011.
2.1. WIND TURBINE
AND WIND FARM DESIGNS
2.1.1 Onshore wind power technologies
Many dierent design concepts of the horizontal-axis
wind turbine are in use. The most common is a three-bladed,
112 m ø
’99
2
stall- or pitch-regulated, horizontal axis machine
operating at near-fixed rotational speed. However, other
concepts for generation are available, notably gearless
“direct drive” turbines with variable speed generator
designs have a significant market share. Wind turbines
will typically start generating electricity at a wind speed
of 3 to 5 metres per second (m/s), reach maximum
power at 15 m/s and generally cut-out at a wind speed of
around 25 m/s.
There are two main methods of controlling the power
output from the rotor blades. The first, and most
common method, is “pitch control”, where the angle
of the rotor blades is actively adjusted by the control
system. This system has built-in braking, as the blades
become stationary when they are fully ‘feathered’. The
126 m ø
126 m ø
160 m ø
’01 ’03 ’05
other method is known as “stall control” and, in this case,
it is the inherent aerodynamic properties of the blade
which determine power output. The twist and thickness
of the rotor blade varies along the length of the blade
and is designed in such a way that turbulence occurs
behind the blade whenever the wind speed becomes
too high. This turbulence means that blade becomes less
eˆcient and as a result minimises the power output at
higher speeds. Stall control machines also have brakes
at the blade base to bring the rotor to a standstill, if the
turbine needs to be stopped for any reason.
In addition to how the output is controlled, the wind
turbine generator can be “fixed speed” or “variable
speed”. The advantages of variable-speed turbines using
direct-drive systems are that the rotors will operate more
eˆciently11, loads on the drive train can be reduced and
pitch adjustments minimised. At rated power, the turbine
essentially becomes a constant speed turbine. However,
these advantages have to be balanced by the additional
cost of the necessary power electronics to enable
variable speed operation.12
11 A fixed rpm wind turbine will have only one wind speed at which the rotors are operating at their optimum eciency.
12 Variable speed operation requires a doubly fed induction generator or the use of direct drive with asynchronous generator.
Airbus 380
wing span
80m
250 m ø
’89
.3
’91 ’93
.5 4.5
5
’10
7.5
?
8/10
1st year of operation
rated capacity (MW)
’87
Rotor diameter (m)

A typical modern wind turbine can be broken down into its
major parts, which are the:
Blades: Modern turbines typically use three blades,
although other configurations are possible. Turbine
blades are typically manufactured from fibreglass-reinforced
polyester or epoxy resin. However, new
materials, such as carbon fibre, are being introduced to
provide the high strength-to-weight ratio needed for the
ever larger wind turbine blades being developed. It is
also possible to manufacture the blades from laminated
wood, although this will restrict the size.
Nacelle: This is the main structure of the turbine and the
main turbine components are housed in this fibreglass
structure.
Rotor Hub: The turbine rotor and hub assembly spins
at a rate of 10 to 25 revolutions per minute (rpm)
depending on turbine size and design (constant or
variable speed). The hub is usually attached to a low-speed
shaft connected to the turbine gearbox. Modern
turbines feature a pitch system to best adjust the angle
of the blades, achieved by the rotation of a bearing
at the base of each blade. This allows rotor rpm to be
controlled and spend more time in the optimal design
range. It also allows the blades to be feathered in high
wind conditions to avoid damage.
Gearbox: This is housed in the nacelle although “direct
drive” designs which do not require one are available. The
gearbox converts the low-speed, high-torque rotation
of the rotor to high-speed rotation (approximately 1 500
rpm) with low-torque for input to the generator.
Generator: The generator is housed in the nacelle
and converts the mechanical energy from the rotor to
electrical energy. Typically, generators operate at 690
volt (V) and provide three-phase alternating current
(AC). Doubly-fed induction generators are standard,
although permanent magnet and asynchronous
generators are also used for direct-drive designs.
Controller: The turbine’s electronic controller monitors
and controls the turbine and collects operational data. A
yaw mechanism ensures that the turbine constantly faces
the wind, Effective implementation of control systems
can have a significant impact on energy output and
loading on a turbine and they are, therefore, becoming
increasingly advanced. The controllers monitor, control
or record a vast number of parameters from rotational
speeds and temperatures of hydraulics, through blade
pitch and nacelle yaw angles to wind speed. The wind
farm operator is therefore able to have full information
and control of the turbines from a remote location.
Tower: These are most commonly tapered, tubular steel
towers. However, concrete towers, concrete bases with
steel upper sections and lattice towers are also used.
Tower heights tend to be very site-specific and depend
on rotor diameter and the wind speed conditions of the
site. Ladders, and frequently elevators in today’s larger
turbines, inside the towers allow access for service
personnel to the nacelle. As tower height increases,
diameter at the base also increases.
Transformer: The transformer is often housed inside the
tower of the turbine. The medium-voltage output from the
generator is stepped up by the transformer to between 10 kV
to 35 kV; depending on the requirements of the local grid.
2.1.2 offshore wind power technologies
Offshore wind farms are at the beginning of their
commercial deployment stage. They have higher capital
costs than onshore wind farms, but this is offset to some
extent by higher capacity factors.13 Ultimately, offshore
wind farms will allow a much greater deployment of
wind in the longer-term. The reasons for the higher
capacity factors and greater potential deployment are
that offshore turbines can be:
»» Taller and have longer blades, which
results in a larger swept area and
therefore higher electricity output.
»» Sited in locations that have higher
average wind speeds and have low
turbulence.
»» Very large wind farms are possible.
»» Less constrained by many of the
siting issues on land. However,
other constraints exist, may be
just as problematic and need to be
adequately considered (e.g. shipping
lanes, visual impact, adequate onshore
infrastructure, etc.).
13 Offshore, average mean wind speeds tend to be higher than onshore, and can increase electricity output by as much as 50% compared to onshore
wind farms (Li, et al., 2010).

FoundationType/
Concept
Aplication Advantages Disadvantages
Mono-piles Most conditions, preferably
shallow water and not deep
soft material. Up to 4 m
diameter. Diameters of 5-6 m
are the next step.
Simple, light and versatile. Of
lengths up to 35 m.
Expensive installation due to large
size. May require pre-drilling a
socket. Difficult to remove.
Multiple-piles (tripod) Most conditions, preferably not
deep soft material. Suits water
depth above 30 m.
Very rigid and versatile. Very expensive construction and
installation. Difficult to remove.
Concrete gravity base Virtually all soil conditions. Float-out installation Expensive due to large weight
Steel gravity base Virtually all soil conditions.
Deeper water than concrete.
Lighter than concrete. Easier
transportation and installation.
Lower expense since the same
crane can be used as for
erection of turbine.
Costly in areas with significant
erosion. Requires a cathodic
protection system. Costly
compared with concrete in shallow
waters.
Mono-suction caisson Sands, soft clays. Inexpensive installation. Easy
removal.
Installation proven in limited range
of materials.
Multiple-suction
caisson (tripod)
Sands and soft clays. Deeper
water.
Inexpensive installation. Easy
removal.
Installation proven in limited range
of materials. More expensive
construction
Floating Deep waters Inexpensive foundation
construction. Less sensitive to
water depth than other types.
Non-rigid, so lower wave loads
High mooring and platform costs.
Excludes fishing and navigation
from areas of farm.
Table 2.2: offshore wind Turbine foundaTion opTions
Source: EWEA, 2004
A key long-term constraint on wind in many countries is
that gaining approval for wind farms with high average
wind speeds close to demand will become more difficult
over time. With the right regulatory environment,
offshore wind farms could help offset this challenge by
allowing large wind turbines to be placed in high average
wind speed areas. Thus, although offshore wind remains
nearly twice as expensive to install as onshore wind,
its longer term prospects are good. As an example, it
is expected that offshore wind installations could have
electricity outputs 50% larger than equivalent onshore
wind farms because of the higher, sustained wind speeds
which exist at sea (IEA, 2010).
Offshore wind turbines for installation in marine
environments were initially based on existing land-based
machines, but dedicated offshore designs are emerging.
The developers and manufacturers of turbines have now
accumulated more than ten years’ experience in offshore
wind power development. Turbines and parts used for
offshore turbines have constantly improved, and knowledge
about the special operating conditions at sea has steadily
expanded. However, reducing the development cost of
offshore wind power is a major challenge.
Offshore turbines are designed to resist the more
challenging wind regime offshore, and require additional
corrosion protection and other measures to resist the
harsh marine environment. The increased capital costs are
the result of higher installation costs for the foundations,
towers and turbines, as well as the additional requirements
to protect the installation from the offshore environment.
The most obvious difference between onshore and offshore
wind farms is the foundations required for offshore wind
turbines. These are more complex structures, involving
greater technical challenges, and must be designed to
survive the harsh marine environment and the impact of
large waves. All these factors and especially the additional
costs of installation mean they cost significantly more than
land-based systems.
Offshore wind farm systems today use three types of
foundation: single-pile structures, gravity structures or
multi-pile structures. The choice of which foundation type
to use depends on the local sea-bed conditions, water
depth and estimated costs. In addition to these techniques,
floating support structures are also being investigated, but
these are only at the RD and pilot project phase.

At present, most of the offshore wind turbines installed
around the world have used a mono-pile structure
and are in shallow water, usually not exceeding 30 m
(IEA, 2009). The most widely used type of mono-pile
structure involves inserting steel tubes with a diameter
of 3-5 into the seabed to a depth of 15-30 using drilling
bores. The merit of this foundation is that a seabed
base is not required and its manufacturing is relatively
simple, but the installation can be relatively difficult
and the load from waves and currents in deeper water
means flexing and fatigue are an issue to be considered.
The key challenge in the longer-term will be to develop
lower cost foundations, particularly for deep-water
offshore where floating platforms will be required.
The future of offshore wind is likely to be based on the
development of larger scale projects, located in deeper
waters in order to increase capacity factor and to have
sufficient space for the large wind turbines to operate
effectively. However, the distance to shore, increased
cable size, deep water foundations and installation
challenges will increase the cost of the wind farm. There
is an economic trade-off that can be very site-specific
The current average capacity of wind turbines installed
at offshore wind farms is 3.4 MW (EWEA, 2011a), up
from 2.9 MW in 2010. Recently installed wind farms
have typically used a 3.6 MW turbine, but 5 MW or
larger turbines are available or under development. The
trend towards larger wind turbines is therefore likely to
continue in the near future; and 5 MW turbines and larger
are likely to dominate offshore installations in the future.14
2.1.3 small wind turbines
Although there is no official definition of what
constitutes a small wind turbine, it is generally
defined as a turbine with a capacity of 100 kW or less.
Compared with utility-scale wind systems, small wind
turbines generally have higher capital costs and achieve
lower capacity factors, but they can meet important
unmet electricity demands and can offer local economic
and social benefits, particularly when used for off-grid
electrification. Small wind turbines share of the total
global wind power market was estimated at around
0.14% in 2010 and is expected to increase to 0.48% by
the year 2020 (GlobalData, 2011).
Small wind turbines can meet the electricity needs of
individual homes, farms, small businesses and villages or
small communities and can be as small as 0.2 kW. They
can play a very important role in rural electrification
schemes in off-grid and mini-grid applications. They can
be a competitive solution for off-grid electrification and
can complement solar photovoltaic systems in off-grid
systems or mini-grids.
Although small wind turbines are a proven technology,
further advances in small wind turbine technology
and manufacturing are required in order to improve
performance and reduce costs. More efficient installation
and maintenance techniques will also help improve the
economics and attractiveness of small wind turbines.
Small wind turbine technologies have steadily improved
since the 1970s, but further work is needed to improve
operating reliability and reduce noise concerns to
acceptable levels. Advanced airfoils, super-magnet
generators, smart power electronics, very tall towers
and low-noise features will not only help improve
performance, but reduce the cost of electricity generated
from small wind turbines.
The deployment of small wind turbines is expanding
rapidly as the technology finally appears to be coming of
age. The development of small wind turbine technology
has mirrored that of large turbines, with a variety of sizes
and styles having been developed, although horizontal
axis wind turbines dominate (95% to 98% of the market).
Currently, some 250 companies in 26 countries are
involved in supplying small wind turbines (AWEA, 2011).
The vast majority of these companies are in the start-up
phase. Less than ten manufacturers in the United States
account for around half the world market for small wind
turbines. After the United States, the United Kingdom
and Canada are the largest markets for small wind. At
the end of 2010, the total installed capacity of small
wind turbines reached 440 MW from 656 000 turbines
(WWEA, 2012)
Almost all current small wind turbines use permanent
magnet generators, direct drive, passive yaw control
and two to three blades. Some turbines use 4-5 blades
to reduce the rotational speed and increase the torque
14 Even larger designs are being developed, but it is unlikely that larger turbines will be installed offshore in any significant numbers in the short- to
medium-term, because the capacity to install even larger turbines is unlikely to be available for some time.

available. Siting is a critical issue for small wind turbines,
as collecting accurate wind measurements is not
economic due the cost and time required relative to the
investment. Siting must therefore be based on experience
and expert judgement, leaving significant room for error.
As a result, many systems perform poorly and can even
suffer accelerated wear and tear from bad siting.
The height of the tower is another key factor for small
wind turbines. Low towers will have low capacity factors
and often expose the turbines to excessive turbulence.
Tall towers help avoid these issues, but increase the cost
significantly compared to the turbine cost. An important
consideration for small wind turbines is their robustness
and maintenance requirements. Reliability needs to be
high, as high operations and maintenance costs can
make small wind turbines uneconomic, while in rural
electrification schemes qualified maintenance personnel
may not be available.
A key challenge for small wind turbines is that they
are generally located close to settlements where
wind speeds are often low and turbulent as a result of
surrounding trees, buildings and other infrastructure.
Designing reliable small wind turbines to perform in
these conditions where noise levels must be very low
is a challenge. As a result, there is increased interest in
vertical-axis technologies given that:
»» They are less affected by turbulent air
than standard horizontal-axis wind
turbines.
»» Have lower installation costs for the
same height as horizontal-axis wind
turbines.
»» They require lower wind speeds
to generate, which increases their
capacity to serve areas with lower
than average wind speeds.
»» They rotate at one-third to one-quarter
the speed of horizontal-axis
turbines, reducing noise and vibration
levels, but at the expense of lower
efficiency.
These advantages mean that small vertical-axis
wind turbines can play a very important role in rural
electrification schemes in off-grid and mini-grid
applications, as and in other niche applications. As a
result of this potential, a range of companies are either
manufacturing or plan to manufacture small-scale,
building-mounted vertical-axis wind turbines.
2.2 the gLobaL Wind energy resource
The overall potential for wind depends heavily on
accurately mapping the wind resource. Efforts to improve
the mapping of the global wind resource are ongoing
and further work will be required to refine estimates
of the wind resource. There is currently a lack of data,
particularly for developing countries and at heights
greater than 80 m (IEA, 2009)
The wind resource is very large, with many parts of
the world having areas with high average wind speeds
onshore and offshore. Virtually all regions have a strong
wind resource, although this is usually not evenly
distributed and is not always located close to demand
centres.
Work is ongoing, by the private and public sector, to
identify the total wind resource in ever more detail in
order to assist policy-makers and project promoters
to identify promising opportunities that can then be
explored in more detail with onsite measurements.
The total wind resource potential depends on a number
of critical assumptions in addition to the average wind
speed, including: turbine size, rotor diameter, density of
turbine placement, portion of land “free” for wind farms,
etc. This is before consideration of whether the wind
resource is located next to demand centres, transmission
bottlenecks, economics of projects in different areas, etc.
Despite these uncertainties, it is clear that the onshore
wind resource is huge and could meet global electricity
demand many times over (Archer and Jacobson, 2005)
and combining the onshore and close-in offshore
potential results in estimates as high as 39 000 TWh
(WBGU, 2003) of sustainable technical potential.

figure 2.2: world wind resource map
Source: 3TIER, 2012

3. Global wind power
market trends
The growth in the wind market was driven by Europe until 2008, as Denmark, and later Germany and Spain,
drove increases in installed capacity. More recently, Italy, France and Portugal have also added significant new
capacity. However, since 2008, new capacity additions have been large in North America and China. In 2011, China
added 17.6 GW of wind capacity, 43% of the global total for 2011 and 70% more than Europe added (GWEC, 2012).
3.1 totaL instaLLed capacity
The wind power industry has experienced an average
growth rate of 27% per year between 2000 and 2011,
and wind power capacity has doubled on average every
three years. A total of 83 countries now use wind power
on a commercial basis and 52 countries increased their
250
200
150
100
50
total wind power capacity in 2010 (REN21, 2011). The new
capacity added in 2011 totalled 41 GW, more than any other
renewable technology (GWEC, 2012). This meant total wind
power capacity at the end of 2011 was 20% higher than at
the end of 2010 and reached 238 GW by the end of 2011
(Figure 3.1).
figure 3.1: global insTalled wind power capaciTy, 1996 To 2011
Source: GWEC, 2012
0
1996 1997 1998 1999 2000 2002 2003 2004 2005 2006 2009 2010 2011
GW
2001 2007 2008

CouNtrY MW %
China 62 364 26.2
united States 46 919 19.7
Germany 29 060 12.2
Spain 21 674 9.1
India 16 084 6.8
France* 6 800 2.9
Italy 6 737 2.8
uK 6 540 2.7
Canada 5 265 2.2
Portugal 4 083 1.7
rest of the world 32 143 13.5
China
26%
United States
20%
* Provisional figure
figure 3.2: The Top Ten counTries by insTalled wind capaciTy, end-2011
Source: GWEC, 2012.
Europe accounted for 41% of the global installed wind
power capacity at the end of 2011, Asia for 35% and
North America for 22%. The top ten countries by installed
capacity accounted for 86% of total installed wind power
capacity worldwide at the end of 2011 (Figure 3.2). China
now has an installed capacity of 62 GW, 24 times the
capacity they had in 2006. China now accounts for 26%
of global installed capacity, up from just 3% in 2006.
Total installed capacity at the end of 2011 in the United
States was 47 GW (20% of the global total), in Germany
it was 29 GW (12%), in Spain it was 22 GW (9%) and in
India it was 16 GW (7%).
Rest or the world
13%
Portugal
Canada 2%
2%
United Kingdom
3%
Italy
France* 3%
3%
India
7%
Spain
9%
Germany
12%
3.2 annuaL capacity additions
The global wind power market was essentially flat in
2009 and 2010, but in 2011 capacity added was 40.6
GW up from 38.8 in 2010 (Figure 3.3). This represents an
investment in new capacity in 2011 of USD 68 billion (EUR
50 billion) (GWEC, 2012). Onshore wind accounted for
97% of all new capacity additions in 2010.
In 2011, the European market added around 10 GW of
new capacity, while in the United States new capacity
additions have rebounded from their lower levels in 2010
to reach 8.1 GW in 2011. If it had not been for the growth
in the Chinese market, global new capacity additions in
2010 would have been significantly lower than in 2009.
Asia, Europe and North America dominated new wind
power capacity additions with the additions of 20.9 GW,
10.2 GW and 8.1 GW respectively in 2011. For the second
year running, more than half of all new wind power was
added outside of the traditional markets of Europe and
North America. This was mainly driven by the continuing

rapid growth in China, which accounted for 43% the new
global wind power installations (17.6 GW). The top ten
countries by capacity additions in 2010 accounted for
88% of the growth in global capacity (Figure 3.4).
However, emerging wind power markets in Latin America
are beginning to take off. Capacity additions in Latin
America and the Caribbean were 120% higher in 2011
than in 2010.
The market is still dominated by onshore wind and there
remain significant onshore wind resources yet to be
exploited. However, the offshore wind market is growing
rapidly, and reached a total installed capacity of 3 118 MW
at the end of 2010. Worldwide, 1 162 MW was added in the
year 2010, a 59.4 % increase over 2009 (WWEA, 2011a).
GW
In Europe, in 2010, 883 MW of new offshore wind
power capacity was added, a 51% increase on 2009
additions. This is at the same time as onshore new
capacity additions declined by 13%. Total offshore
wind capacity in Europe reached 2.9 GW at the
end of 2010. The size of offshore wind farms is also
increasing. In 2010, the average size of offshore
wind farms was 155 MW, more than double the 2009
average of 72 MW (EWEA, 2011b). Preliminary data for
2011 suggests offshore wind power capacity in Europe
increased by 866 MW (EWEA, 2011a).
Other countries are also looking at offshore wind, and
significant new offshore capacity should be added in
the coming years in the United States, China and other
emerging markets.
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
45
40
35
30
25
20
15
10
5
figure 3.3: global new wind power capaciTy addiTions, 1996 To 2011
Source: GWEC, 2011 ; and WWEA, 2012.
0

* Provisional figure
United Kingdom
3%
Germany
5%
figure 3.4: Top Ten counTries by new wind power capaciTy addiTions in 2011
Source: GWEC and WWEA, 2012.
United States
17%
France*
2%
Italy
2%
Canada
3%
Spain
3%
India
7%
China
43%
Sweden
2%
Rest or the world
12%
CouNtrY MW %
China 17 631 43
uSa 6 810 17
India 3 019 7
Germany 2 086 5
uK 1 293 3.2
Canada 1 267 3.1
Spain 1 050 2.6
Italy 950 2.3
France* 830 2
Sweden 763 1.9
rest of the world 4 865 12
3.3 future projections
of capacity groWth
The wind industry has faced a difficult period, as low
order levels during the financial crisis translated into lower
capacity additions in 2010 compared with 2009, in the key
markets of Europe and North America. However, global
capacity still increased by one-quarter in 2010 and the
outlook for the coming years is cautiously optimistic.
The world market for wind energy experienced solid
growth in the first half of 2011, recovering from a weak
year in 2010. Total installed capacity worldwide reached
215 GW by the end of June 2011, and 239 GW by the end
of 2011.
The current analysis of the market suggests that as much as
85 GW of new capacity could come online in the next one
to two years based on the project pipeline for wind power

projects already in the process of being commissioned,
constructed or which have secured financing (Figure 3.5).
The United Kingdom could become a significant player in
the European market in the coming years.
The offshore market is likely to be driven by the United
Kingdom and Germany, while France and Sweden also
have significant projects in the pipeline. The interest in
offshore wind is also increasing in China which already
has around 150 MW in the water and has plans to deploy
5 GW by 2015 and 30 GW by 2020, while the United
States has also discussed significant deployment.
In 2011, offshore wind power capacity in Europe grew
by 866 MW, with 348 MW installed in the first half of
the year. In 2011 there were 11 offshore wind farms under
development in Europe, which, when all completed, will
have a capacity of nearly 2.8 GW (EWEA, 2011a). This is
likely to be just the beginning of the offshore expansion
in Europe, as a total of 19 GW of offshore wind power
projects have received planning approval, although it
remains to be seen how much of this capacity will actually
be constructed (EWEA, 2011b). The United Kingdom has a
significant number of offshore projects in the pipeline and
could become the largest offshore market.
The Global Wind Energy Council (GWEC) is projecting
that new capacity additions will increase out to 2015.
New capacity additions are projected to grow from 41
GW in 2011 to 62.5 GW in 2015 (Figure 3.6). If these
projections come to pass, global installed wind capacity
will reach 460 GW by 2015, 2.3 times the total installed
capacity in 2010. Other projections are even higher,
the World Wind Energy Association projects a global
capacity of 600 GW by 2015 (WWEA, 2011a).
Asia, Europe and North America will continue to drive
new capacity additions in the foreseeable future. China is
likely to continue to dominate new capacity additions, as
ambitious plans and supportive policies align. Although
new capacity additions may not grow as rapidly as they
have in recent years, even so China has plans to reach
200 GW of installed capacity by 2020. India is likely
to emerge as an important new market, with capacity
additions of 2 GW to 3 GW per year. Overall, new
capacity additions in Asia could increase from 21.5 GW in
United States
Other Asia and Pacific
2,3%
Other Central and South America
Spain
5,1%
2,7%
figure 3.5: wind power projecTs parTially commissioned, under consTrucTion or wiTh financing secured (84.8 gw).
Source: BNEF, 2011a.
9%
Canada
1,9%
United Kingdom
8,2%
Italy
2,3%
India
3,3%
China
33,2%
Africa
1,4%
Other Europe
8,9%
Germany
3,1%
Brazil
2,1%

500
400
300
200
100
25%
20%
15%
10%
5%
2010 2011 2012 2013 2014 2015
annual new capacity (GW) Cumulative capacity (GW) annual new capacity
growth rate (%)
Cumulative capacity
growth rate (%)
figure 3.6: projecTed growTh in global wind power annual capaciTy addiTions and cumulaTive insTalled capaciTy, 2010 To 2015
Source: GWEC, 2011.
0
0%
2010 to 28 GW in 2015 (GWEC, 2011). This implies that by
2015 Asia could have a total of 185 GW of installed wind
capacity, displacing Europe as the region with the highest
installed capacity.
The outlook in North America is considerably more
uncertain, due to legislative uncertainties and the
ongoing impact of weak economic fundamentals, but
new capacity additions could increase to 12 GW in 2015.
In Europe new capacity additions should increase to 14 GW
by 2015 and total installed capacity to 146 GW by the end
of that year.
In Latin America new capacity additions are projected
to grow strongly from 0.7 GW in 2010 to 5 GW in 2015,
increasing cumulative installed capacity from 2 GW to 19
GW. This rate of growth is less than the excellent wind
resource could support, but encouraging developments
in Brazil, Mexico and Chile are offset by a lack of
political commitment and supportive policy frameworks
elsewhere.
The outlook for Africa and the Middle East is particularly
uncertain, but new capacity additions could increase
ten-fold from 0.2 GW in 2010 to 2 GW in 2015. Africa
has an excellent wind resource, although it is not evenly
distributed, and there is potential for Africa to see much
stronger growth rates in the future.
GW

4. Current cost of wind power
Like other renewable energy technologies, wind is capital intensive, but has no fuel costs. The key parameters
governing wind power economics are the:
zz Investment costs (including those associated with project financing);
zz Operation and maintenance costs (fixed and variable);
zz Capacity factor (based on wind speeds and turbine availability factor);
zz Economic lifetime; and
zz Cost of capital.
Although capital intensive, wind energy is one of the most cost-effective renewable technologies in terms of the
cost per kWh of electricity generated.
4.1. a breakdoWn of the instaLLed
capitaL cost for Wind
The installed cost of a wind power project is dominated
by the upfront capital cost (often referred to as CAPEX)
for the wind turbines (including towers and installation)
and this can be as much as 84% of the total installed
cost. Similarly to other renewable technologies, the high
upfront costs of wind power can be a barrier to their
uptake, despite the fact there is no fuel price risk once
the wind farm is built. The capital costs of a wind power
project can be broken down into the following major
categories:
»» The turbine cost: including blades,
figure 4.1: capiTal cosT breakdown for a Typical onshore wind power sysTem and Turbine
Source: Blanco, 2009.
tower and transformer;
»» Civil works: including construction
costs for site preparation and the
foundations for the towers;
»» Grid connection costs: This can
include transformers and subs-stations,
as well as the connection to
the local distribution or transmission
network; and
»» Other capital costs: these can include
the construction of buildings, control
systems, project consultancy costs, etc.
Grid connection
11%
Planning Miscellaneous
9%
Foundation
16%
Wind Turbines
64%
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
Generator
transformer
Power Converter
Gearbox
rotor blades
tower
other
turbine Cost Distribution

Table 4.1: comparison of capiTal cosT breakdown for Typical onshore and offshore wind power sysTems in developed counTries, 2011
Source: Blanco, 2009; EWEA, 2009; Douglas-Westwood, 2010; and Make Consulting, 2011c.
For the turbine, the largest costs components are the
rotor blades, the tower and the gearbox. Together, these
three items account for around 50% to 60% of the turbine
cost. The generator, transformer and power converter
account for about 13% of the turbine costs, with the
balance of “other” costs being made up miscellaneous
costs associated with the tower, such as the rotor hub,
cabling and rotor shaft. Overall, the turbine accounts for
between 64% to as much as 84% of the total installed
costs, with the grid connection, civil works and other costs
accounting for the rest (Blanco, 2009 and EWEA, 2009).
The reality is that the share of different cost components
varies by country and project, depending on turbine
costs, site requirements, the competitiveness of the
local wind industry and the cost structure of the country
where the project is being developed. Table 4.2 shows
typical ranges for onshore and offshore wind farms.
4.2. totaL instaLLed capitaL
costs of Wind poWer
systems, 1980 to 2010
The installed cost of wind power projects is currently in
the range of USD 1 700/kW to USD 2 150/kW for onshore
wind farms in developed countries (Wiser and Bolinger,
2011 and IEA Wind, 2011a). However, in China, where
around half of recent new wind was added, installed
costs are just USD 1 300/kW.
Onshore Offshore
Capital investment costs (USD/kW) 1 700-2 450 3 300-5 000
Wind turbine cost share (%)1 65-84 30-50
Grid connection cost share (%) 2 9-14 15-30
Construction cost share (%) 3 4-16 15-25
Other capital cost share (%) 4 4-10 8-30
1 Wind turbine costs includes the turbine production, transportation and installation of the turbine.
2 Grid connection costs include cabling, substations and buildings.
3 The construction costs include transportation and installation of wind turbine and tower, construction wind turbine foundation
(tower), and building roads and other related infrastructure required for installation of wind turbines.
4 Other capital cost here include development and engineering costs, licensing procedures, consultancy and permits, SCADA
(Supervisory, Control and Data Acquisition) and monitoring systems.
Although global time series data are not readily available,
data for the United States show that installed costs declined
significantly between the early 1980s and 2001. Between
2001 and 2004, the average installed cost of projects in
the United States was around USD 1 300/kW (Wiser and
Bolinger, 2011). However, after 2004 the installed cost of
wind increased steadily to around USD 2 000/kW; with
data for 2010 and 2011 suggesting a plateau in prices may
have been reached.
The reasons for these price increases are several, and include:
»» The rapidly rising cost of commodities
in general, and steel and copper prices
in particular. In offshore projects, copper
and steel alone can account for as much
as 20% to 40% of the total project cost.
»» The shift to offshore developments may
be raising average installed costs in
Europe. This is being accelerated by the
shift from a shallow water market driven
by Denmark to deeper water projects in
the United Kingdom and Germany.
»» Growing pains and more sophisticated
systems. Market demand grew so
rapidly that the supply chain and human
capacity required had difficulty keeping
up15 with demand and shortages in
15 This was compounded by policy uncertainty, which left some companies hesitant to invest in new capacity.

certain components – notably, wind
turbines, gear boxes, blades, bearings
and towers – and led to higher costs.
The increasing sophistication of turbine
design, component integration and grid
interaction also pushed up prices.
The plateau in data for the United States suggests that
for onshore wind installations, the supply chain has
progressively caught up with demand, aided by more
stable (but still volatile) commodity prices. Increased
competition at a global level is also helping, especially
the emergence of manufacturers with significant local
content in countries with low-cost manufacturing bases.
For offshore wind, the market is still quite immature and
mainly located in Europe. Costs for offshore wind projects
vary, but are in the range USD 3 300 to USD 5 000/kW. This
market was shared by Vestas and Siemens in 2010 and
by Siemens and Bard in the first half of 2011. However,
2.0
1.8
1.6
1.4
1.2
1.0
the Chinese market is growing and new markets are
ready to start, notably in the United States and Korea,
while several manufacturers – including Spanish, Chinese,
Japanese and Koreans – are positioning themselves for
growth in the offshore market.
4.2.1 Wind turbine costs
The wind turbine is the largest single cost component of
the total installed cost of a wind farm. Wind turbine prices
increased steadily in recent years, but appear to have
peaked in 2009. Between 2000 and 2002 turbine prices
averaged USD 700/kW, but this had risen to USD 1 500/
kW in the United States and USD 1 800/kW in Europe
in 2009. Since the peak of USD 1 800/kW for contracts
with a 2009 delivery, wind turbine prices in Europe have
declined by 18% for contracts with delivery scheduled in
the first half of 2010 (Figure 4.2). Global turbine contracts
for delivery in the second half of 2010 and the first half
of 2011 have averaged USD 1 470/kW, down by 15% from
peak values of USD 1 730/kW (BNEF, 2011b).
figure 4.2: wind Turbine price index by delivery daTe, 2004 To 2012
Source: BNEF, 2011b.
0.6
H1
2004
H2
2004
H1
2005
H2
2005
H1
2006
H2
2006
H1
2007
H2
2007
H1
2008
H2
2008
H1
2009
H2
2009
H1
2010
H2
2010
H1
2011
H1
2012
H2
2011
0.8
Wind turbine prices, (2010 USD thousands/kW)
1.13
1.23
1.35 1.37
1.26
1.43
1.47 1.46
1.57 1.57
1.73 1.71
1.51
1.46
1.40 1.40 1.40

644/kW in 2010 (WWEA, 2011). In contrast, Japan and
Austria appear to have the highest costs, with turbine
prices of around USD 2 000/kW and USD 2 100/kW in
2010 respectively (IEA Wind, 2011a). Of the developed
countries, the United States and Portugal appear to have
the lowest prices for wind turbines. The reasons for this
wide variation include the impact of lower labour costs in
some countries, local low-cost manufacturers, the degree
of competition in a specific market, the bargaining power
of market actors, the nature and structure of support
policies for wind, as well as site specific factors.
Wind turbine prices have declined significantly since
their peak in 2007/2008 in most countries (the notable
exception being Japan). Prices were between 11% and
29% lower than their values in 2008 in the countries for
which a consistent set of data is available (Figure 4.5).
China, which is now the most important wind market,
experienced the highest percentage decline and had the
lowest absolute wind turbine prices in 2010.
Polynominal
trend line
R² = 0.65422
Oct ’95 Jul ’98 Apr ’01 Jan ’04 Oct ’06 Jul ’09 Apr ’12
The wind turbine prices quoted for recent transactions in
developed countries are in the range of USD 1 100 to USD
1 400/kW (Bloomberg NEF, 2011b). The recent decline in
wind turbine prices reflects increased competition among
wind turbine manufacturers, as well as lower commodity
prices for steel, copper and cement.
Data for the United States market has followed a similar
trend. Average wind turbine prices more than doubled
from a low of around USD 700/kW between 2000 and
2002 to USD 1 500/kW in 2008 and 2009 (Figure 4.3).16
In the United States market, this increase in wind turbine
prices accounted for 95% of the increase in total installed
wind costs over the same period.
Analysis of different markets suggests that there is quite
a wide variation in wind turbine prices, depending on
the cost structure of the local market. China appears to
have the lowest prices, with a turbine price of just USD
2500
2000
1500
1000
500
0
figure 4.3: reporTed wind Turbine TransacTion prices in The uniTed sTaTes, 1997 To 2012
Source: Wiser and Bolinger, 2011.
2010 USD/kW
16 This is based on a dataset of 471 completed wind power projects in the continental United States, which represent 33 517 MW, or roughly 83% of all
wind power capacity installed at the end of 2010. The dataset also includes a small sample of projects installed in 2011.

Table 4.2: average wind Turbine prices (real) by counTry, 2006 To 2010
Wind Turbine Price
2006 2007 2008 2009 2010
2010 USD/kW
Australia -- -- -- 1 635 1 725
Austria -- -- 2 384 2 053 2 123
Canada -- -- -- 1 685 --
China 885 928 911 864 644
Denmark 1 147 -- -- -- --
Germany 1 333 -- 1 699 -- --
Greece -- -- -- -- --
India -- -- -- -- --
Ireland -- 1 730 1 639 1 380 1 460
Italy 1 290 1 874 1 892 1 798 1 592
Japan 865 1 652 1 713 2 123 1 991
Mexico -- -- -- 1 557 1 526
Netherlands -- -- -- --
Norway 1 238 -- -- --
Portugal 1 086 1 478 1 581 1 593 1 261
Spain -- -- -- 1 317 --
Sweden -- -- -- 1 607 1 858
Switzerland -- -- 2 160 2 053 1 924
United Kingdom -- -- -- --
United States 1 183 1 224 1 456 1 339 1 234
Note: Data were converted to USD using the following USD/euro exchange rates: 1.256 in 2006, 1.371 in 2007, 1.472 in 2008, 1.393 in 2009 and 1.327 in
2010 (IMF, 2011).
Sources: IEA Wind 2007, 2008, 2009, 2010 and 2011a and 2011b; and WWEA/CWEA, 2011.

How a wind turbine comes together Gearbox 12.91%
Box 1
A BREAKDOWN OF WIND TURBINE COSTS
A typical wind turbine will contain up to 8000 di erent components.
This guide shows the main parts and their contribution in percentage
terms to the overall cost. Figures are based on a REpower MM92
turbine with 45.3 metre length blades and a 100 metre tower.
Rotor hub
FIGURE 4.4: WIND TURBINE COST BREAKDOWN (5 MW OFFSHORE WIND TURBINE)
Source: EWEA, 2007
The wind turbine is the most expensive
component of most wind farms. Figure 4.4
presents an example of the indicative cost
breakdown for a large offshore wind turbine.
The reality is that a range of costs exists,
depending on the country, maturity of the wind
industry in that country and project specifics.
The two most expensive components are the
towers and rotor blades, with these contributing
around half of the total cost. After these two
components, the next largest cost component
is the gearbox. But this underestimates the
importance of gearboxes, as these generally
are an important part of the OM costs, as
they can require extensive maintenance.
Onshore wind turbines, with their smaller sizes,
will tend to have slightly lower shares for the
tower and blades.
Tower 26.3%
Range in height from 40 metres up to more
than 100 m. Usually manufactured in sec-tions
from rolled steel; a lattice structure or
concrete are cheaper options.
Rotor blades 22.2%
Varying in length up to more than 60 me-tres,
blades are manufactured in specially
designed moulds from composite materi-als,
usually a combination of glass fibre
and epoxy resin. Options include polyester
instead of epoxy and the addition of carbon
fi bre to add strength and sti ness.
1.37%
Made from cast iron, the hub holds the
blades in position as they turn.
Rotor bearings
1.22%
Some of the many di erent bearings in a
turbine, these have to withstand the varying
forces and loads generated by the wind.
Main shaft 1.91%
Transfers the rotational force of the rotor to
the gearbox.
Main frame 2.80%
Made from steel, must be strong enough to
support the entire turbine drive train, but not
too heavy.
Gears increase the low rotational speed of
the rotor shaft in several stages to the high
speed needed to drive the generator
Generator 3.44%
Converts mechanical energy into electrical
energy. Both synchronous and asynchronous
generators are used.
Yaw system 1.25%
Mechanism that rotates the nacelle to face
the changing wind direction.
Pitch system 2.66%
Adjusts the angle of the blades to make best
use of the prevailing wind.
Power converter 5.01%
Converts direct current from the generator
into alternating current to be exported to the
grid network.
Transformer 3.59%
Converts the electricity from the turbine to
higher voltage required by the grid.
Brake system 1.32%
Disc brakes bring the turbine to a halt when
required.
Nacelle housing 1.35%
Lightweight glass fi bre box covers the tur-bine’s
drive train.
Cables 0.96%
Link individual turbines in a wind farm to an
electricity sub-station.
Screws 1.04%
Hold the main components in place, must be
designed for extreme loads.

2500
2000
1500
1000
500
figure 4.5: wind Turbine cosT in selecTed counTries, 2008 and 2010
In the United States wind turbine costs declined by 15%
between 2008 and 2010, and data for February 2011
suggests a decline of 17%, which could translate into a
full year reduction for 2001 of 20% to 25% compared to
the 2008 peak.
4.2.2 grid connection costs
Wind farms can be connected to electricity grids via
the transmission network or distribution network. In the
former case, transformers will be required to step-up to
higher voltages than if the wind farm is feeding into the
distribution network. This will tend to increase costs. If
the grid connection point is not far from the wind farm,
the connection is typically a high voltage alternating
current (HVAC) connection. Over longer distances it may
make sense to use a high voltage direct current (HVDC)
link, as the reduced losses over this link will more than
offset the losses in converting to direct current and back
again to alternating current. It has been estimated that
HVDC connections will be attractive for distances over
50 km in the future (Douglas-Westwood, 2010).
Sources: IEA Wind 2009 and 2011a; and WWEA/CWEA, 2011.
2010 USD/kW
0
Austria China Ireland Italy Japan Portugal Switzerland United States
Grid connection costs can also vary significantly by
country depending on who bears what costs for grid
connection cost. For example, in some regimes, it is
the transmission system operator that bears the cost
of any transmission system upgrade required by the
connection of a wind farm, in other regimes, the wind
farm owner will be required to pay for these costs.
Grid connection costs (including the electrical work,
electricity lines and the connection point) are typically
11% to 14% of the total capital cost of onshore wind
farms and 15% to 30% of offshore wind farms (Douglas-
Westwood, 2010).
4.2.3 civil works and construction costs
The construction costs include transportation and
installation of wind turbine and tower, the construction
of the wind turbine foundation (tower), and the
construction of access roads and other related
infrastructure required for the wind farm.

2000
1600
1200
800
400
8000
6000
4000
2000
figure 4.6: copper and sTeel prices, 1990 To 2010
Source: Based on data from World Bank, 2008; US Steel 2009; and UNCTAD, 2010.
Copper price (2010 USD/tonne)
Steel price (2010 USD/tonne)
The main foundation type onshore are a poured concrete
foundation, while offshore it is currently driven/drilled
steel monopiles. However, other types of foundations
are possible (e.g. suction, caisson, guyed towers, floating
foundations and self-installing concepts using telescopic
towers) and will be required for offshore developments
in deep water. Foundations are material-intensive, with
45% to 50% of the cost of monopile foundations being
attributable to the steel required (Junginger, 2004).
Cost reductions for foundations can be made through
economies of scale, reduced material consumption and
reduced material cost.
Figure 4.6 shows the commodity price development
between 1990 and 2010 for copper and (structural) steel,
both essential metals for wind power deployment. The
market price of these commodities has undergone a
substantial increase since 2005, with a peak (reached
around 2007/2008) about three times its average pre-
2005 level. While prices of both metals subsequently
declined, in 2010 they were still approximately twice as
high as they were throughout the 1990s.
The transportation and installation of the wind
turbines and towers are also a major cost component.
The increase in the average size of wind turbines
has increased the absolute cost per wind turbine,
but transport and installation costs have not grown
proportionately to turbine size, helping to reduce the
relative importance of these costs in onshore wind
farms. Offshore, these costs are much higher than
onshore and a shortage of purpose-built vessels and
cranes means that these costs are unlikely to decline
rapidly in the near future until this constraint eases.
The construction of vessels and cranes specifically
designed to install wind turbines therefore offers an
opportunity to reduce installation time and costs. An
idea of the potential is that purpose-built installation
ships in Denmark have reduced the average installation
time per wind turbine from 3 days to 1.4 days
(Junginger, 2004).
4.3 operations and
maintenance costs
The fixed and variable operations and maintenance
(OM) costs are a significant part of the overall LCOE
of wind power. OM costs typically account for 20% to
25% of the total LCOE of current wind power systems
(EWEA, 2009).
0
0
Cooper
Steel
1990 1995 2000 2005 2010

Actual OM costs from commissioned projects are not
widely available. Even where data are available, care
must be taken in extrapolating historical OM costs
given the dramatic changes in wind turbine technology
that have occurred over the last two decades. However,
it is clear that annual average OM costs of wind power
systems have declined substantially since 1980. In the
United States, data for completed projects suggest
that total OM costs (fixed and variable) have declined
from around USD 33/MWh for 24 projects that were
completed in the 1980s to USD 22/MWh for 27 projects
installed in the 1990s and to USD 10/MWh for the 65
projects installed in the 2000s.17
The data are widely distributed, suggesting that OM
costs, or at least their reporting, are far from uniform
across projects. However, since the year 2000 OM
Average Annual OM Cost (2010 USD/MWh)
70
60
50
40
30
20
10
0
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
17 Although what is included in the OM costs is not clearly defined, in most cases the reported values appear to include the costs of wages and
materials associated with operating and maintaining the facility, as well as rent (i.e. land lease payments). Other expenses, including taxes, property
insurance, and workers’ compensation insurance, are generally not included.
18 Assumptions for Italy assume that OM costs rise from 1% of installed capacity in year 1 to 4% in year 20 (IEA Wind, 2011b).
costs appear to be lower and to be more uniform across
projects than was the case prior to 2000. This decline in
OM costs may be due to the fact more recent projects
use larger, more sophisticated turbines and have higher
capacity factors (reducing the fixed OM costs per unit
of energy produced).
Another important consideration for wind energy is
the fact that OM costs are not evenly distributed over
time. They tend to increase as the length of time from
commissioning increases. This is due to an increasing
probability of component failures and that when a failure
does occur it will tend to be outside the manufacturer’s
warranty period. Although the data to support this
hypothesis are not widely available, data for a limited
number of projects in the United States suggest that this
could be correct (Figure 4.8).18
figure 4.7: om cosTs for wind power projecTs in The uniTed sTaTes, 1980 To 2008
Note: The data are for the year a wind power system started commercial operation.
Projects with no 2008 OM data
Projects with 2008 OM data

25
20
15
10
5
1 2 3 4 5 6 7 8 9 10
19 It is worth noting that in some electricity markets, depending on their rules for wind projects, there will be some variable costs associated with power
system services, such as reactive power compensation.
figure 4.8: om cosTs in The uniTed sTaTes by number of years since sTarT of commercial operaTion
0
2010 USD/MWh
Number of years since first commercial operation
Unfortunately, not all sources separate out fixed
and variable OM costs, and it is not uncommon for
OM costs to be quoted as a total of USD/kW/year.
This section will thus present the two together to
comparability of different sources. Fixed OM costs
typically include insurance, administration, fixed
grid access fees and service contracts for scheduled
maintenance. Variable OM costs typically include
scheduled and unscheduled maintenance not covered
by fixed contracts, as well as replacement parts and
materials, and other labour costs.19 Maintenance
measures may be small and frequent (replacement of
small parts, periodic verification procedures, etc.), or
large and infrequent (unscheduled repair of significant
damage or the replacement of principal components).
OM costs appear to be the lowest in the United States
at around USD 0.01/kWh (USD 10/MWh), perhaps due
to the scale of the market and the long experience with
wind power. European countries tend to have higher cost
structures for OM for onshore wind projects.
OM costs for offshore wind farms are significantly
higher than for onshore wind farms due to the higher
costs involved in accessing and conducting maintenance
on the wind turbines, cabling and towers. Maintenance
costs are also higher as a result of the harsh marine
environment and the higher expected failure rate for
some components. Overall, OM costs are expected to be
in the range of USD 0.027 to USD 0.054/kWh (USD 27 to
USD 54/MWh) (ECN, 2011).
Given that offshore wind farms are at the beginning
of their deployment phase, OM costs remain highly
project-specific and it will take time for learning to
reduce costs and for a clear trend to emerge. However, it
is clear that reducing OM costs for offshore wind farms
remains a key challenge and one that will help improve
the economics of offshore wind.
Year of entry in service
1998-2003 2004-2009

Table 4.3: om cosTs for onshore wind projecTs
Austria 0.038
Denmark 0.0144 - 0.018
Finland 35 - 38
Germany 64
Italy 47
Japan 71
The Netherlands 0.013 – 0.017 35
Norway 0.020 – 0.037
Spain 0.027
Sweden 0.010 – 0.033
Switzerland 0.043
United States 0.010
Variable, USD/kWh Fixed, USD/kW/year
Source: IEA Wind, 2011
4.4 totaL instaLLed cost of Wind
poWer systems
Onshore wind
The installed capital costs for wind power systems vary
significantly depending on the maturity of the market
and the local cost structure. China and Denmark have
the lowest installed capital costs for new onshore
projects of between USD 1 300/kW and USD 1 384/kW
in 2010. Other low cost countries include Greece, India,
and Portugal (see Table 4.4 and Figure 4.9).
A detailed analysis of the United States market
shows that the installed cost of wind power projects
decreased steadily from the early 1980s to 2001, before
rising as increased costs for raw materials and other
commodities, coupled with more sophisticated wind
power systems and supply chain constraints pushed up
wind turbine costs (Figure 4.10). However, installed costs
appear to have peaked. The capacity-weighted average
installed cost of wind projects built in 2010 in the United
States was USD 2 155/kW virtually unchanged from the
2009 figure of USD 2 144/kW in 2009. The initial data
for 2011 suggest a slight decline in installed costs, driven
by lower turbine costs.
The full year outlook for 2011 is therefore that installed
costs should be slightly lower than 2010 in the United
States and this trend should continue into 2012, as most
developers are expecting further decreases in turbine
prices for delivery in 2012. This trend is unlikely to be
reversed in the short- to medium-term and will be
replicated globally, as low-cost manufacturers (notably in
China) start to enter the global market for turbines.
There are considerable economies of scale in wind power
developments, as projects under 5 MW have significantly
higher total installed costs than larger systems (Figure
4.11). However, there do not appear to be significant
economies of scale beyond shifting into the 5 MW to 20
MW range or higher. In 2009 and 2010, the 6.8 GW (53
projects) installed at 100 MW to 200 MW capacity wind
farms, had around the same total installed costs as the
257 MW (21 projects) installed in the 5 MW to 20 MW
range. Without data from other regions to verify this
trend in the United States, it is difficult to identify why
this might be.

2003 2004 2005 2006 2007 2008 2009 2010
Australia 2 566 1 991 - 3 318
Austria 2 477 2 256 - 2 654
Canada 865 785 1 367 1 855 2 268 1 749 2 336 1 975 - 2 468
China 0 0 0 0 1 472 1 463 1 392 1 287 - 1354
Denmark 790 725 886 1 331 1 503 1 759 1 840 1 367
Finland 922 836 924 0 1 893 2 126 2 134 2 100
Germany 1 044 956 1 084 1 750 1 979 2 174 2 122 1 773 - 2 330
Greece 959 862 952 1426 1 586 1 639 2 265 1 460 - 1 858
India 0 0 0 0 1 075 1 152 1 194 1 460
Ireland 1 034 973 0 0 2 883 2 533 2 268 2 419
Italy 846 853 943 1 629 2 595 2 682 2 463 2 339
Japan 818 734 943 1 643 1 856 2 980 3 185 3 024
Mexico 1 477 1 466 1 982 2 016
Netherlands 1 044 956 1 037 1 494 1 637 1 788 1 876 1 781
Norway 1 175 853 971 1 652 1 977 2 227 2 196 1 830
Portugal 1 063 939 1 094 1 589 1 874 1 932 1 982 1 327 - 1 858
Spain 903 802 896 1 657 1 802 2 086 1 770 1 882
Sweden 969 853 0 0 1 893 2 239 2 598 2 123
Switzerland 1 688 2 808 2 669 2 533
United Kingdom 0 879 1 433 1 714 1 981 1 955 1 858 1 734
United States 752 683 849 1 522 1 840 2 124 2 144 2 154
Table 4.4: onshore wind power sysTem insTalled cosTs for selecTed counTries, 2003 To 2010
Onshore wind power system installed cost
2010 USD/kW
Sources: IEA Wind, 2007, 2008, 2009, 2010 and 2011; and WWEA/CWEC, 2011.

0 500 1000 1500 2000 2500 3000 3500
Italy
United Kingdom
Netherlands
Portugal
Germany
Japan
Sweden
Greece
Spain
Canada
Ireland
Denmark
United States
Finland
Norway
China
figure 4.9: onshore wind power sysTem insTalled cosT for selecTed counTries, 2007 To 2010
2010 USD/kW
India
2007
2008
2009
2010

5000
4000
3000
2000
1000
figure 4.10: insTalled cosT of wind power projecTs in The uniTed sTaTes, 1982 To 2011
3000
2500
2000
1500
1000
500
figure 4.11: average insTalled cosT of wind power projecTs in The uniTed sTaTes by projecT size, 2009 and 2010
0
2010 USD/KW 2010 USD/KW
1983 1987 1991 1995 1999 2003 2007 2011
0
5 MW
31 projects
54 MW
5-20 MW
21 projects
257 MW
20-50 MW
19 projects
750 MW
50-100 MW
45 projects
3571 MW
100-200 MW
53 projects
6989 MW
200 MW
13 projects
3070 MW

4500
4000
3500
3000
2500
2000
1500
1000
500
Individual Project cost
Capacity-Weighted Average Project Cost
figure 4.12: insTalled cosT of wind power projecTs in The uniTed sTaTes by Turbine size: 2009 and 2010
35
30
25
20
15
10
5
figure 4.13: The capaciTy-weighTed average capaciTy facTors for projecTs in The uniTed sTaTes, 1999 To 2010
Installed Project Cost (2010 USD/KW)
Turbine size
Capacity Factor (%)
Year
Projects
GW
1999
6
0.5
2000
12
1.0
2001
41
1.5
2002
85
3.3
2003
98
3.8
2004
118
5.2
2005
144
5.9
2006
169
8.7
2007
212
10.7
2008
256
15.7
2009
358
24.4
2010
338
32.0
0
based on Estimated Generation (if
no curtailment in subset or regions)
4 year Moving average
(based on estimated generation)
0
1 MW
13 MW
10 projects
2.5 MW
950 MW
12 projects
1-1.75 MW
7 505 MW
98 projects
1.75-2.5 MW
6224 MW
61 projects
based on actual Generation
(with curtailment)

Offshore wind
The capital cost of offshore wind power is around twice
that of onshore wind energy projects. The higher cost is
due to increased investments in laying cables offshore,
constructing expensive foundations at sea, transporting
materials and turbines to the wind farm, and installing
foundations, equipment and the turbines themselves. The
turbines, although based on onshore designs, are also
more expensive. They need to be designed with additional
protection against corrosion and the harsh marine
environment to help reduce maintenance costs, which are
also higher offshore (Douglas-Westwood, 2010).
A recent Douglas-Westwood study initiated by The
Research Council of Norway (RCN) provides a detailed
analysis of offshore wind power (Douglas-Westwood,
2010). The study describes recent trends in installed
offshore wind power project costs, wind turbine
transaction prices, project performance and OM costs.
Cra base Case
EIa aEo 2010
EIa aEo 2011 (2010)
IEa EtP 2010
NaS NrC (2009)
EPa (2010)
NrEL offshore 2010
Source: Douglas-Westwood, 2010.
Shifting to larger turbine sizes with taller towers and
larger rotor blades has contributed to increased output
and to a lower LCOE for wind. However, looking at
just one year, shifting to larger turbine sizes appears
to significantly reduce the range of installed costs for
projects, but the actual average cost reduction is small
(weighted by capacity), at least in the United States
(Figure 4.12).
The main benefit of larger turbines and hub heights
therefore appears to be in20 allowing turbines to access
higher average wind speeds, have larger swept areas for
the rotors and therefore achieve higher capacity factors.
In the United States, the capacity-weighted average
capacity factors for projects peaked in 2008 (for projects
installed in 2007) at around 35%, but have since settled
at around 31% to 32%.21 (Figure 4.13)
Overnight Capital Cost (2010 USD/kW)
7000
6000
5000
4000
3000
2000
1000
0
figure 4.14 esTimaTes of offshore wind power capiTal cosTs
20 The data also suggest that wind farms with larger turbines also have a narrower range of costs. However, this is likely to be driven by the fact that
larger turbines are chosen for larger wind farms which will result in more competitive prices.
21 This includes an estimated allowance added back in for curtailment of wind generation for grid or system stability/capability reasons. This
compensation for curtailment is, however, based on calculations with data for only a subset of regions. As a result, the true capacity factor is likely to
have been somewhat higher. The data are also not corrected for the natural variations in the wind resource to any long term average; therefore, the
four year moving average is a better indicator of the real trend in capacity factors.

Table 4.5: capiTal cosT sTrucTure of offshore wind power sysTems, 2010
Source: Douglas-Westwood, 2010.
Share of total cost
(%)
Cost (USD/kW) Sub- Components Cost share of
sub-components (%)
Wind turbine 44 1 970 Nacelle
Blades
Gearbox
Generator
Controller
Rotor hub
Transformer
Tower
Other
2
20
15
4
10
5
4
25
15
Foundations 16 712 - -
Electrical
infrastructure
17 762 Small array cable
Large array cable
Substation
Export cable
4
11
50
36
Installation 13 580 Turbine installation
Foundation installation
Electrical installation
20
50
30
Planning and
development
10 447 - -
Total 100% 4 471
The largest cost component for offshore wind farms
is still the wind turbine, but it accounts for less than
half (44%) of the total capital costs. Based on a price
assessment of wind turbines of the major manufacturers,
and other research into the component costs, it was
estimated that the average price of an offshore wind
turbine was around USD 1 970/kW (Douglas-Westwood,
2010). The foundations, electrical infrastructure,
installation and project planning account 16%, 17%, 13%
and 10% of the total costs, respectively.
According to the estimates of Douglas-Westwood, the
current capital cost of the offshore wind power system
for typical shallow water and semi-near shore conditions
in the UK is USD 4 471/kW which is almost 2.5 times
higher than onshore wind case (Douglas-Westwood,
2010). The cost of offshore wind electricity is estimated
at USD 0.162/kWh. This is calculated using current capital
and operational costs, a 20 year lifespan, 38% capacity
factor and a 7% discount rate. The additional costs due to
variability are modest and could add an additional USD
0.003/kWh to the LCOE (Douglas-Westwood, 2010).
Small wind turbines
The capital costs and the cost of the energy produced
by small wind turbines are still higher than large-scale
wind turbines (AWEA, 2011 and IEA Wind, 2010). The
cost of small wind turbines varies widely depending on
the competitiveness of the market and factors affecting
installation, but costs for a well-sited turbine tend to
range between USD 3 000 to USD 6 000/kW. The
average installed price of a small wind turbine system
in the United States is USD 4 400/kW and USD 5 430/
kW in Canada (AWEA, 2011 and CanWEA, 2010). Costs
are significantly lower in China, and range between USD
1 500 to USD 3 000/kW depending upon the quality and
reliability. The LCOE of small wind is in range of USD 0.15
to USD 0.35/kWh (IEA Wind, 2010), estimated operations
and maintenance (OM) costs range between USD 0.01
to USD 0.05/kWh (AWEA, 2011).

The recent increases in wind turbine prices makes projecting cost reductions for wind power projects in the
short-term challenging. However, estimating cost reductions is important if policy makers, energy companies
and project developers are to have robust information in order to compare between renewable power generation
projects and conventional power generation technologies.
5. Wind power cost
reduction potentials
Numerous studies have looked at where cost reductions
could be achieved and how large these savings might
be. Most analysis has looked at quantitative estimates
of cost reduction possibilities for onshore wind, but
there is an increasing number of studies that have done
this for offshore wind. Most of these studies focus on
cost reductions caused by improved designs of wind
farms. However, other factors (e.g. learning-by-doing,
standardization and economies of scale) may also
contribute significantly to cost reductions. The improved
performance of wind turbines and their location in higher
average wind speed locations will also help to reduce the
LCOE of wind by improving the average capacity factor.
For offshore wind, cost reductions in other industries, such as
the offshore oil and gas sector and offshore cable laying, will
also have benefits for wind. At the same time, developments
in commodity prices, particularly steel, copper and cement,
will also influence wind power cost reduction potentials
depending on how they evolve over time.
For onshore and offshore wind power projects the key cost
components, and hence areas for cost reduction, are:
»» Wind turbines;
»» Foundations;
»» Grid connection/cabling;
»» Installation; and
»» Project planning and development.
To achieve significant reductions in the LCOE of wind
will require efforts to reduce the costs of each of these
components of a wind power project. At the same
time, efforts to improve the yield of wind farms (i.e. the
capacity factor) will also need to be pursued.
Historical learning rates for wind power were around 10%
prior to 2004, when wind turbine prices grew strongly.
Solar photovoltaic experienced a similar divergence
from its historical learning curve due to supply chain
bottlenecks, but once these were overcome, prices
returned to their historical trend. It is not yet clear
whether or not the installed cost of wind power will
return to the trend seen between the 1980s and 2004.
Current projections by the IEA and GWEC are based
on a learning rate of 7%, but lower values may also
be possible. Increased competition, particularly from
emerging market manufacturers will help keep costs
down and will likely lead to a consolidation among wind
manufacturers, helping to increase economies of scale.
An alternative approach is to look at the cost reduction
potential from a bottom-up perspective, although these
are often informed by learning rates as well. Recent
analysis for the United Kingdom suggests that onshore
wind farm costs could be 12% lower by 2020 than
they are in 2011 and 23% lower by 2040. The largest
percentage and absolute cost reductions come from the
wind turbines. Wind turbines are projected to be 15%
cheaper in 2020 than in 2011 and 28% cheaper in 2040.
The sections that follow discuss these cost reduction
potentials in more detail.
5.1 cost reduction potentiaL
by source
Wind turbine cost reductions in the last two decades,
for both onshore and offshore wind turbines, have been
achieved by economies of scale and learning effects as
installed capacity has grown. The LCOE of wind has been
further reduced as the result of higher capacity factors
that have come from increasing turbine height and rotor
diameter. Onshore, wind turbines are typically in the 2

3.00
2.50
2.00
1.50
figure 5.1: hisTorical learning raTe for wind Turbines, 1984 To 2010
Development 100 98 93 98% 93%
Turbine 870 737 630 85% 72%
Foundation 170 159 144 93% 84%
Electrical 100 91 83 91% 83%
Insurance 40 37 34 93% 84%
Contingencies 70 65 59 93% 84%
Total 1 350 1 187 1 042 88% 77%
Wind turbine price
2010 USD million/MW
Cumulative capacity, MW
Table 5.1: projecTed capiTal cosTs for small-scale wind farms (16 mw) wiTh 2 mw Turbines in The uniTed kingdom, 2011 To 2040
2011 2020 2040 % of 2011
cost in 2020
% of 2011
cost in 2040
Source: Mott MacDonald, 2011.
0
200 1 600 12 800 102 400
0.50
1984
1990
1995
2000 2005
2010 bNEF
WtPI
Current wind
turbine prices
Public
data
Note: WTPI = Wind turbine price index

MW to 3 MW size range, while offshore the average is
higher at around 3.4 MW per turbine for projects in 2011
(EWEA, 2011b). This compares to less than one megawatt
in 2000 (EWEA, 2011b). The growth in the average size of
onshore turbines will slow as increasing wind farm heights
on land will become increasingly difficult. The increase in
the average size of offshore wind turbines will continue as
increased rotor height and diameter allow greater energy
yields.
The reason for this growth is simple; the LCOE of wind
energy can be reduced significantly by having larger
rotors and higher hub heights. This is because, all other
things being equal, the energy yield of a turbine is
roughly proportional to the swept area of the rotors.
Similarly, all other things being equal, the energy yield is
roughly proportional to the square root of the hub height
due to higher wind speeds at greater heights (although
surrounding terrain can affect this).
However, the increase in the size of turbines and blades
also increases their weight, increasing the cost of towers
and the foundations. Historically the increase in the
weight of turbines has been limited by the utilisation of
lighter materials and the optimisation of design, although
it is not clear if this trend can continue. As a result, there
appears to be relatively small economies of scale from
larger turbines, their main benefit being the increased
energy yield and scale given to wind farms.
Recent trends in wind turbine prices suggest that wind
turbine prices have peaked. It is difficult to predict
the evolution of wind turbine prices, but increasing
competition among manufacturers and the emergence
of large-scale wind turbine manufacturing bases in China
and other emerging economies is likely to put continued
downward pressure on wind turbine prices in the short-to
medium-term. The current global manufacturing
surplus in all major components of wind turbines
also suggests that there are no major supply chain
bottlenecks that could disrupt this trend in the next few
years (MAKE Consulting, 2011a).
The largest cost reductions will therefore come from
learning effects in wind turbine manufacturing, with
smaller, but important contributions from the remaining
areas. By 2020, wind turbine costs may decline by
15% compared to 2011 levels (Mott Macdonald, 2011)
and perhaps by more than this if oversupply pushes
down manufacturers’ margins, or emerging market
manufacturers gain larger shares of the European and
North American markets.
The key cost reduction areas for wind turbines (Douglas-
Westwood, 2010) are:
»» Towers: These are an important part
of the wind turbine cost (up to one-quarter),
but are a relatively mature
component. Most are rolled steel, with
costs being driven by steel prices.
However, increased competition, the
integration of lightweight materials
and the more distributed location of
manufacturers that will be possible as
markets expand means tower costs
may come down, perhaps by 15% to
20% by 2030.
»» Blades: Wind turbine rotor blades can
account for one-fifth of turbine costs.
The key driver behind blade design
evolution is weight minimisation as
this reduces loads and helps improve
efficiency. Using more carbon fibre in
blades, as well as improving the design
of blades (with production efficiency
and aerodynamic efficiency in mind)
can help reduce weight and costs,
although the high cost of carbon fibre
is a problem. Cost reductions of 10% to
20% could be possible by 2020.
»» Gearboxes: Typically represent 13%
to 15% of wind turbine costs The RD
focus for gearboxes is to improve
reliability and reduce costs. Vertical
integration of gearbox manufacturing
by wind turbine suppliers should help
reduce costs. Cost reductions may
also stem from the increasing share
of gearless drive generators using
permanent magnet synchronous
motors. Overall, cost reductions could
reach 15% by 2020.
»» Other components:22 The most
significant remaining components are
22 See Figure 4.4.

the generator, control systems (including
pitch and yaw systems), transformer and
power converter. These components,
as well as the other miscellaneous
components of the turbine, all have
opportunities for cost reductions
through increased manufacturing
efficiency and RD efforts. These
components could see cost reductions
of 10% to 15% by 2020.
The cost reduction potentials in percentage terms
are likely to be similar for onshore and offshore wind
turbines, as the technology improves and designs
become further standardised. Significant savings are
expected to be realised through the mass production
of wind turbines, the vertical integration of turbine
manufacturers as they bring more components “in-house”
and learning effects. The absolute reduction in
costs for offshore wind turbines will be somewhat higher
than for onshore turbines (on a per kW basis) given their
higher overall cost.
One area where offshore wind farms will have a cost
advantage is through scale. Offshore wind projects have
the possibility to be very large compared to onshore
wind farms and this will allow very competitive prices for
large wind turbine orders.
Cost reductions for grid connections
The cost of grid connection is not likely to decline
significantly for onshore wind farms. However, offshore
developments can expect to see cost reductions as
the scale of wind farms developed increases and
as the industry capacity increases. The cost of long
distance grid connections for wind farms far from shore
could be reduced by using HVDC (high-voltage direct
current) connections. Costs are coming down for these
connections and lower losses could make them more
economical overall, even taking into account the cost
of converting the DC to AC onshore. The costs for the
internal grid connection are estimated to be constant
and only contribute a minor share of the investment
costs associated with an offshore wind farm.
Cost reductions for foundations
The foundations can account for 7-10% of onshore wind
farm costs and 15% to 20% (EWEA, 2009) or more for
offshore wind farms. The largest cost components of
foundations are cement and steel. Actual foundation
costs will therefore be strongly influenced by these
commodity prices. However, some cost reductions
are still possible as costs will increase somewhat less
proportionately than the increase in swept rotor area,
so larger turbines will help reduce specific installation
costs somewhat (EWEA, 2009). Other cost reductions
can come from economies of scale, reduced material
consumption (through more efficient designs) and
reduced materials cost (materials substitution). It has
been estimated that if steel costs decline by 1-2%/year
and can result in a 5-10% reduction in overall foundation
costs (Junginger, 2004).
The potential for reducing the cost of offshore wind
turbine foundations is higher than for onshore.
Offshore foundations are typically at least 2.5 times
more expensive than onshore ones (EWEA, 2009).
The trend to larger wind turbines, improved designs,
reduced installation times and larger production lines for
foundations will help reduce costs.
However, for shallow, fixed foundations (predominantly
monopiles), cost reductions will be modest. For
deeper offshore foundations the dynamics are more
complicated. Fixed seabed foundations in greater than
20 m of water become increasingly expensive as deeper
piles are required and wave and current forces can be
greater. Significant cost reductions are therefore not
obvious. It is likely that fixed seabed foundations will be
uneconomic beyond a depth of around 40 m and floating
foundations will be required.
Floating foundations are more expensive than shallow
monopole foundations, but cost reduction potentials are
significantly larger, as a range of innovative designs are being
explored. Today’s floating foundations are predominantly
demonstrator projects. As experience is gained and RD
advances, designers will be able to identify foundation types
with the greatest potential. The costs of floating foundations
could decline by 50% by 2030 (Douglas-Westwood, 2010),
although they are still likely to be a third more expensive than
shallow water monopole foundations.
Other cost reductions
The remaining project costs for onshore wind farms are
typically in the range of 8% to 18%, with 10% typical for
wind farm based on 2 MW wind turbines (EWEA, 2009).
Offshore, this proportion is higher and likely to be in the
range of 25% to 35%. Modest cost reductions can be
expected for the remaining electrical installation, controls,

civil works, consultancy and projects costs onshore, but
the potentials offshore are larger as the industry learns
from experience. Costs could be reduced by between 20%
and 30% by 2030 (Douglas-Westwood, 2010).
Installation and commissioning costs, particularly for
offshore wind farms, could be reduced, despite the
increasing size and weight of turbines making this
process more difficult. Specialised installation vessels will
provide reduced installation times.
However, the largest cost reduction possibility is the
so-called “all in one” installation, where the wind turbine
is fully assembled onshore, transported to the already
installed foundation and installed in one piece. This
technique is just beginning to be evaluated, with two
projects to date having used this method: the Beatrice
Demonstrator in Scotland and the Shanghai Bridge
project in China. Turbine installation costs offshore
could be reduced by as much as 30% by 2030 (Douglas-
Westwood, 2010).
Speeding up the installation process and electrical
installations should help reduce commissioning time
significantly, reducing working capital requirements
and bringing forward the date when first revenue from
electricity sales occurs.
Cost reductions due to increased efficiency
The capacity factor for a wind farm is determined by the
average wind speed at the location and the hub height.
The energy that can be harvested is also a function of
the swept rotor area. Thus, tall turbines with larger rotor
areas in high average mean wind speed areas will have
the highest capacity factors and energy yields. One
of the main advantages of offshore wind power is its
ability to obtain increased capacity factors compared
to equivalent capacity onshore installations. This is due
in part to opportunities to place the wind farms in high
average wind speed environments, but also because
objections to very tall wind turbines are sometimes less
of an issue.
Considerable information on wind resource mapping
across Europe and the USA has been accumulated
and it is extending to other areas of the world, where
the development of wind power has the potential to
contribute to the energy mix. Increased access to wind
mapping information will have a significant impact on
maximising yield and minimising generation cost by
reducing the information barrier to identifying the best
sights for wind farm development.
Continuing improvements in the ability to model
turbulence with computational fluid dynamics (CFD) can
help improve designs and increase the responsiveness
of machines in turbulent conditions. At the same time,
the use of a radar on top of the nacelle to “read” the
wind 200 to 400 metres in front of the turbine can allow
appropriate yaw and pitch adjustments in anticipation
of shifts or changes in the wind. It is thought that these
improvements will both increase efficiency and reduce
wear and tear on the machine by reducing the frequency
and amplitude of shear loads on the rotor.
Cost reductions in offshore wind power: A summary
Currently, the capital cost of offshore wind is around
two times higher than onshore wind. If offshore wind is to
become truly competitive, capital and OM costs need to
be reduced. The outlook for cost reductions is good and
when combined with the ability to achieve higher capacity
factors than onshore, it means that the LCOE of offshore
wind could come down significantly in the long term.
The main drivers for cost reductions will be continued
design improvements, the upscaling of wind turbines,
the continuing growth of offshore wind capacity
(learning effects) and the development and high
utilization rates of purpose-built installation vessels.
Other factors that will help reduce costs are stable
commodity prices, technological development of HVDC
converter stations and cables, standardisation of turbine
and foundation design, and economies of scale for
wind turbine production. An overview of key factors
influencing cost reductions for offshore wind farms is
presented in Table 5.2.
It is expected that offshore wind power installations will
move further offshore in order to maximise electricity
generating capability through the utilisation of stronger
and more consistent winds. In some cases, this shift is in
order to site the wind farm closer to main consumption
centres (e.g. London Array), and to provide reduced
impact from visual obstruction and noise-related issues.
Shifting to further offshore and deeper water
environments with more extreme offshore weather
conditions that are unfamiliar and unpredictable can
result in significantly higher costs for all components

Table 5.2: summary of cosT reducTion opporTuniTies for offshore wind
IEA -18 -23
EWEA -11 -22 -28 -29
GWEC -5 to -6 -9 to -12 -16 to -18
Mott MacDonald -12 -23
US DOE -10
Specific offshore wind developments Exogenous development
Source: Junginger, 2004.
Wind turbine Upscaling
Improved design
Standardisation
Economies of scale
Further development of onshore turbines
Steel price
Grid Connection Standardising the design of HVDC cables
Applicability of XLPE insulation to HVDC
cables
Advances in valve technology and
power electronics
Further development and
diffusion of submarine
HVDC interconnectors
Foundation Standardisation
Economies of scale
Steel price
Installation Learning-by-doing
Development and structural
purpose-built ships
Optimisation of ship use
Standardisation of turbines and
equipment
Oil price
Table 5.3: differenT esTimaTes of The poTenTial for cosT reducTions in The insTalled cosT of onshore wind, 2011 To 2050
2015 2020 2025 2030 2035 2040 2045 2050
(%)
Sources: DOE, 2008; GWEC and Greenpeace, 2010; EWEA, 2011c; IEA, 2009 and Mott MacDonald, 2011

of offshore wind power due to the associated risk; high
prices will continue until adequate experience is gained.
5.2 overaLL cost reduction
potentiaLs
There are currently no major supply bottlenecks in the
wind turbine industry, at least globally, as the result of
the rapid expansion of manufacturing capacity in all
critical areas. It is projected that wind turbine prices
will decline in the coming years as a result, but to what
extent is difficult to gauge and depends on the impact of
turbine manufacturers based in emerging economies on
OECD markets.
It is thus possible, perhaps even likely, that wind
turbine costs will revert to a trend similar to the one
evident between the 1980s and 2004. The IEA and
GWEC assume that the learning rate will be slightly
lower than this historical average at 7% (IEA, 2009 and
GWEC, 2011). Table 5.3 presents projections of the cost
reductions for total installed wind farm costs between
now and 2050 from a variety of sources. Projected
cost reductions vary depending on the base year of the
analysis, with recent studies using base years of 2009,
2010 or 2011 but also due to different assumptions about
engineering costs, learning rates, and global deployment
of wind in the future. Cost reductions to 2015 are in the
range of 5% to 11%, while by 2020 the estimated cost
reduction range widens to 9% to 22%.
Estimates of the cost reduction potential for offshore wind
are quite uncertain given the fact that the offshore wind
industry is just at the beginning of its development. Recent
analysis has identified cost reduction potentials of 11%
to 30% by 2030, depending on how rapidly the industry
expands (Douglas-Westwood, 2010). The key to reducing
costs will be through learning effects, more RD, wind
turbine capacity increases, expansion of the supply chain,
greater dedicated installation capacity (to reduce reliance
on offshore oil and gas industry) and more competition.
However, cost reduction potentials could be higher, as
supply chain constraints and lack of competition have been
estimated to have inflated installed costs by around 15%
(Mott MacDonald, 2011). In this scenario, learning effects,
moving to larger wind farms with larger turbines, increased
supply chain development, and greater competition – as
well as potential breakthroughs from novel wind turbine
designs and foundations – could see costs fall by 28% by
2020 and by 43% by 2040. However, these reductions
remain highly uncertain and variations of plus or minus 20%
in 2040 are possible. Taking into account the increased
capacity factors achieved by offshore wind turbines
as they get continually larger means that capital costs
(undiscounted) per MWh generated could drop by 55% by
2040 (Mott MacDonald, 2011).

6. Levelised cost of
electricity from wind power
The levelised cost of energy (LCOE) is the primary metric for describing and comparing the underlying
economics of power projects. For wind power, the LCOE represents the sum of all costs of a fully operational
wind power system over the lifetime of the project with financial flows discounted to a common year. The principal
components of the LCOE of wind power systems include capital costs, operation and maintenance costs and the
expected annual energy production (Figure 6.1). Assessing the cost of a wind power system requires a careful
evaluation of all of these components over the life of the project.
FIGURE 6.1: THE ECONOMICS OF WIND SYSTEMS
Rotor diameter,
hub height and
other physical
characteristics
Source: Based on EWEA, 2009.
6.1 COST STRUCTURE OF
LARGE-SCALE WIND FARMS
The key parameters that define the LCOE for wind
power systems are the capital costs, wind resource
quality, technical characteristics of the wind turbines
and the discount rate. Other costs are the variable costs,
including operations and maintenance costs. Of these
parameters, the capital cost is the most significant, with
the wind turbines themselves accounting for 64% to 84%
(EWEA, 2009) of the total investment costs for onshore
wind farms in Europe. A breakdown of the capital cost
structure for onshore and oŠshore wind power systems
are shown in Figure 6.1.
Lifetime of
project
Cost
of capital
Wind
turbines and
installation
Capital costs
per year
Cost of energy
per Kwh
Annual
energy
production
mean wind
speed + site
characteristics
Price of turbines,
foundations, road
construction, etc.
Operation
maintenance
cost per year
Total cost
per year
% p.a.
$/kWh
kWh

Onshore cost distribution Offshore cost distribution
the range USD 1 850 to USD 2 200 in the major developed
country markets of the United States, Germany and Spain.
Table 6.1 presents the assumptions for onshore wind capital
costs for typical projects in Europe, North America and
China/India for 2011, as well as the assumed values for 2015.
Offshore wind costs remain high at around USD 4 000/
kW or more, but installed capacity is still very low, and
offshore wind offers the opportunity to have higher
load factors than onshore wind farms, increasing the
electricity yield. However, OM costs will remain higher
than onshore wind farms due to the harsh marine
environment and the costs of access. It is assumed
that costs will decline by 8% between 2011 and 2015 to
around USD 3 700/kW on average, with costs in the
range USD 3 500 to USD 3900/kW.
2010 2011 2015
(2010 USD/kW)
China/India 1 100 to 1 400 1 050 to 1 350 950 to 1 250
Europe* 1 850 to 2 100 1 800 to 2 050 1 700 to 1 950
North America 2 000 to 2 200 1 950 to 2 150 1 800 to 2 050
Grid connection
11%
Planning
miscellaneous
9%
Foundation
16%
figure 6.2: capiTal cosT breakdowns for Typical onshore and offshore wind sysTems
Source: Blanco, 2009.
6.1.1 the capital costs of onshore and
offshore wind farms
The overall capital cost for onshore wind farms depends
heavily on wind turbine prices. They account for between
64% and 85% of the total capital costs and most, if not
almost all, variations in total project costs over the last ten
years can be explained by variations in the cost of wind
turbines. Grid connection costs, foundations, electrical
equipment, project finance costs, road construction, etc.
make up most of the balance of capital costs.
Based on the data and analysis presented earlier (Chapter
Four) wind turbine costs ranged from less than USD 700/kW
in China up to around USD 1 500/kW in developed countries
in 2011. The total installed capital costs, including all other
cost factors, are as little as USD 1 300/kW in China and in
Foundation
installation
27%
Wind turbines
64%
Others
2%
Turbine
system
51%
Array cabling
7%
Transmission
13%
Table 6.1: ToTal insTalled cosTs for onshore wind farms in china/india, europe and norTh america, 2010, 2011 and 2015
Note: * These are typical values for the larger European wind markets in 2010 (Germany, Spain, Sweden and the United Kingdom).

6.1.2 om costs for onshore and offshore
wind farms
The overall contribution of OM costs to the LCOE of
wind energy is significant. Data for seven countries show
that OM costs accounted for between 11% and 30%
of the total LCOE of onshore wind power. The lowest
contribution was in the United States and the highest in
the Netherlands (Figure 6.3).
Best practice OM costs are in the order of USD 0.01/
kWh in the United States. Europe appears to have a
higher cost structure, with best practice of around USD
0.013 to USD 0.015/kWh. However, average OM costs in
Europe are higher at around USD 0.02/kWh. No changes
in OM costs are assumed in North America between
now and 2015, while OM costs in Europe begin to
converge on the European best practice level.
Robust data for the OM costs for offshore wind farms
has yet to emerge. However, current wind farms have
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
figure 6.3: share of om in The ToTal lcoe of wind power in seven counTries
Source: IEA Wind, 2011b.
0%
Denmark Germany Netherlands Spain Sweden Switzerland United States
oM Capital costs
costs of USD 0.025 to USD 0.05/kWh in Europe (ECN,
2011). There are opportunities for cost reductions,
particularly through increases in wind farm scale, but it
remains to be seen to what extent costs can be reduced.
OM costs are assumed to decline by 5% by 2015.
6.2. recent estimates of the Lcoe of
onshore and offshore Wind
The LCOE of onshore wind has fallen strongly since the
first commercial wind farms were developed. In the
United States, the cost of electricity generated from wind
fell from about USD 0.30/kWh in 1984 to a low of around
USD 0.055/kWh in the United States in 2005 (Wiser and
Bolinger, 2011). A similar trend occurred in Europe, where
the LCOE of wind declined by 40% between 1987 and
2006 for wind farms on good coastal sites.
However, the supply chain constraints and demand
growth that led to wind turbine cost increases from

120
100
80
60
40
20
figure 6.4: wind power prices in The uniTed sTaTes by sTarT year, 1998/1999 To 2010
2006 also resulted in a slight growth in the LCOE of
onshore wind between 2005 and 2010, despite improving
capacity factors (see Figure 6.4).
In the United States, this trend was particularly pronounced,
with the capacity-weighted LCOE of wind power projects
more than doubling from 2004/2005 to 2010.
Although there is considerable variation in the LCOE of
projects installed in the United States, the general trend
has been one of increasing costs. The capacity-weighted
average prices reached an all-time low in 2002/2003,
before rising to USD 0.073/kWh in 2010. This is up from
an average of USD 0.062/kWh for projects built in 2009,
and is more than twice the average of USD 0.032/kWh in
2002/2003 prices (Wiser and Bolinger, 2011).
According to the other sources in 2010, price of the utility
scale wind farms worldwide ranged from USD 0.05 to
USD 0.085/kWh, excluding the local and state taxes and
depending on site-specific factors, such as the strength
of the wind resource, turbine size and development and
installation costs.
Other sources recently noted that the LCOE generated
from wind is now below USD 0.068/kWh (€0.050/kWh)
for most of the projects in high resource areas (United
States , Brazil, Sweden, Mexico) (Cleantechnica, 2011).
This compares to current estimated average costs of
USD 0.067/kWh for coal-fired power and USD 0.056/
kWh for gas-fired power.
Recent data for wind auctions in Brazil tend to suggest that
these values are not unrealistic. There has been a steady
decline in the price demanded in the wind auctions since
2009 (Figure 6.5). The 2009 auction saw prices of between
USD 0.09 and USD 0.10/kWh, but by 2011 the price range
was between USD 0.065 and US 0.070/kWh. However,
although the trend in this data for Brazil is robust, the
absolute values of the data have to be treated with caution.23
1998-99
14 projects
655 MW
2000-01
22 projects
856 MW
2002-03
33 projects
1648 MW
2004-05
21 projects
1269 MW
2006
14 projects
742 MW
2007
23 projects
3013 MW
2008
31 projects
2669 MW
2009
48 projects
3819 MW
2010
26 projects
2361 MW
0
2010 USD/MWh
Capacity-Weighted Average 2010 wind power price (by project vintage)
Individual project 2010 wind power price (by project vintage)
23 Question marks also remain about whether some project developers can actually meet the auction prices.

Our analysis based on the data and analysis presented
earlier show that wind turbine and the total installed
capital costs are decreasing again. Reductions in average
OM costs for onshore wind are also possible, with
wind turbine manufacturers increasingly competing
on warranties and OM agreements. Recent analyses
estimate the LCOE from onshore wind power projects to
be USD 0.06 to USD 0.11/kWh (Lazard 2009). However,
the exact value depends on project specifics (e.g. the
wind turbines’ capacity factor) and different sources often
use different boundaries (i.e. some studies include tax
incentives, others don’t).
The LCOE of offshore wind power differs significantly
compared to onshore wind power. While the cost of
electricity generated from a typical onshore wind
power shows a gradual reduction, having falling by 15%
110
90
70
figure 6.5: wind aucTion prices in brazil, 2009 To 2011
since Q2 2009, that of offshore wind has increased
(see Figure 6.6) (BNEF, 2011b). This divergence is due to
the higher capital costs of offshore wind developments
in recent years.
As can be seen from Figure 6.6, the trend in offshore
wind LCOE differ significantly from onshore wind, and
are increasing gradually rather than decreasing. The main
reason for this is the increasing distance from shore. As
offshore wind farms are going to be located far from
shore, costs increase in all aspects of the supply chain.
Turbine prices are increasing due to design improvements
to achieve high reliability in the harsh sea environment
and larger, more sophisticated wind turbines in order to
increase capacity factors. The construction and cabling
costs are also increasing as a function of sea depth and
distance from shore.
Source: CCEE, 2012.
2010 USD/MWh
MW
auction 2010 / delivery in 2013
50
200 400 600 800 1000 1200 1400 1600 1800

250
200
150
100
50
figure 6.6: wind power lcoe Trends for period from Q2 2009 To Q2 2011 .
0
Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011
Nominal USD/MWh
Wind - onshore Wind - offshore
6.3. Lcoe estimates for 2011 to 2015
The estimated cost of wind power varies significantly,
depending on the capacity factor, which in turn depends
on the quality of the wind resource and the technical
characteristics of the wind turbines. Capacity factors
can vary significantly onshore and offshore, with
higher capacity factors achievable in general offshore,
particularly in Europe.
Onshore wind
The LCOE for onshore wind is presented in Figures 6.7
and 6.8 for Europe and North America. High and low
assumptions for the capital costs are taken from Table 6.1
and are based on the data presented earlier. The LCOE
of onshore wind for Europe and North America does
not vary significantly as slightly lower capital costs for
typical European projects are offset by lower OM costs
in the United States in particular. In contrast, the very low
capital costs of projects in China and India mean that, for
a given capacity factor, the LCOE of wind is 31% to 45%
lower than in North America and 36% to 46% lower than
in Europe.
The estimated LCOE of wind for Europe in 2011 was
between USD 0.10 and USD 0.13/kWh. This is based on
the assumption that the typical load factor in Europe for
new projects in 2011 was in the range of 25% to 30% for
onshore projects (IEA Wind, 2011).24 The cost reductions
assumed by 2015 reduce the LCOE of wind by between
6% and 7% for a given capacity factor.
24 Analysis by the IEA Wind Implementing Agreement is based on typical projects in 2008. However, this is likely to be representative of projects in 2011.

Assumes a 10% cost of capital
20% 25% 30% 35% 40% 45% 50%
18
16
14
12
10
8
6
4
2010 US cents per KWh
figure 6.7: The lcoe of wind for Typical european onshore wind farms, 2011 To 2015
Note: Assumes a 10% discount rate, a 20 year lifetime, a 0.1% decline in production per year (wear and tear) and OM costs of USD 0.02/kWh that
increase 1% per year for first ten years and then at 2% per year. For 2015, the assumed OM costs are USD 0.0175/kWh.
Capacity factor
Europe 2011 uSD 1800/kW
The estimated LCOE of wind in North America in 2011,
assuming a capacity factor of 30%, was between USD
0.10 and USD 0.11/kWh. However, the range of capacity
factors reported for 2010 projects in the United States
varied widely, from as little as 20% to a high of 46%
(Wiser and Bolinger, 2011). Using this range implies the
LCOE for wind in North America ranged from as low
as USD 0.07/kWh to a high of as much as USD 0.16/
kWh. By 2015, cost reductions could reduce the LCOE of
wind in North America by 5% to 9% for a given capacity
factor. Given that a range of factors in the United States
resulted in lower capacity factors than might otherwise
have been expected (Wiser and Bolinger, 2011), the
weighted average capacity factor could increase from
30% to 35% in 2015. This would reduce the LCOE of wind
in North America to between USD 0.08 to USD 0.09/
kWh in 2015, or by between 18% and 20% compared to
the average value for 2011.
In China and India installed costs for onshore wind farms
as low as one half that of the level seen in developing
countries in 2010 and 2011. The LCOE of wind is therefore
significantly lower than in Europe or North America for
a given capacity factor. In India in 2010, the average
capacity factor for data from four states with around
four-fifths of total capacity in India was 20%, but there
has been a trend towards higher capacity factors over
time. This trend is expected to continue in the future
(GWEC/WISE/IWTMA, 2011). Assuming a capacity factor
of 25% for new projects, the LCOE of wind in China and
India in 2011 was between USD 0.07 and USD 0.08/kWh
(Figure 6.9). This is 34% to 43% lower than the LCOE of
wind in Europe and North America for the same capacity
factor. However, given the higher average capacity
factors of new projects in Europe (in general) and in
North America, the actual difference in LCOE will be
lower than this.

20% 25% 30% 35% 40% 45% 50%
18
16
14
12
10
8
6
figure 6.8: The lcoe of wind for Typical norTh american onshore wind farms, 2011 To 2015
Capacity factor
North america 2011 uSD 1950/kW
4
China and India already have very competitive installed
costs for wind projects compared to the norm in developed
countries. The opportunities for cost reductions, although
still possible, are smaller than in developed countries.
There is even the potential for average installed costs to
rise somewhat by 2015 if manufacturing costs in emerging
economies start to raise the cost of wind turbines and
engineering projects in general, or if the supply situation
becomes tighter.
Sensitivity to the discount rate used: Onshore wind
The analysis in this section assumes that the average cost
of capital for a project is 10%. However, the cost of debt and
the required return on equity, as well as the ratio of debt-to-equity
varies between individual projects and countries. This
can have a significant impact on the average cost of capital
and the LCOE of a wind power project.
In the United States, the quarterly average required
return on equity for wind projects between the fourth
quarter of 2009 and the fourth quarter of 2010, inclusive,
ranged from a low of 8% to a high of 14.5%. While
over the same period, the quarterly average cost of
debt for wind projects ranged from a low of 4.9% to a
high of 11%.25 Making the simple assumption that the
debt-to-equity ratio is between 50% and 80% and that
debt maturity matches project length results in project
discount rates of between 5.5% and 12.6%.26
Table 6.2 presents the impact of varying the discount
rate between 5.5% and 14.5% for wind power projects in
the United States at different capacity factors. The near
halving of the discount rate to 5.5% reduces the LCOE of
the wind generated by between 9% and 16% depending
on the capacity factor. In contrast, increasing the
25 This data comes from the Renewable Energy Financing Tracking Initiative database and was accessed in November 2011. See https://financere.nrel.
gov/finance/REFTI
26 These assumptions aren’t representative of how projects are structured, but in the absence of comprehensive data are used for illustrative purposes.

discount rate to 12.6% increases the LCOE of the wind
generated by between 26% and 30%, depending on the
capacity factor. This asymmetry is due to the impact of
OM costs and highlights the importance of working to
reduce these over time.
Offshore wind
The LCOE ranges for offshore wind are presented
in Figure 6.10. The LCOE of offshore wind is around
twice that of onshore wind for a given capacity factor
in Europe and North America. However, a better
comparison is one assuming a 10% higher capacity
factor for offshore wind. In this case the LCOE of
offshore wind is 43% to 91% more expensive than
onshore wind. Assuming a 15% higher capacity factor for
wind results in the LCOE of offshore wind being 26% to
75% more expensive.
The LCOE of offshore wind, assuming a 45% capacity
factor and USD 0.035/kWh OM cost, is between USD
0.15 and USD 0.165/kWh. This range drops to USD 0.139
5.5% discount rate 9.65 8.45 7.55 6.85 6.35
10% discount rate 11.55 9.85 8.55 7.65 6.95
12.6% discount rate 14.55 12.45 10.95 9.85 9.05
14.5% discount rate 16.05 13.65 12.05 10.75 9.85
to USD 0.152/kWh when the capacity factor is 50%. The
high OM costs of offshore wind farms add significantly
to the LCOE of offshore wind farms and cost reductions
in this area will be critical to improving their long-term
economics.
The total installed cost of offshore wind farms is
assumed to decline by 8% by 2015 and OM costs from
an average of USD 0.035/kWh to USD 0.03/kWh. These
cost reductions translate into the LCOE from offshore
wind being between 8% and 10% lower in 2015 than in
2011. The LCOE from offshore wind is likely to remain
higher than onshore wind, even taking into account
the higher capacity factors, for the foreseeable future
and will probably always be more expensive given the
challenges involved in reducing capital costs and OM
costs. However, with the increased competition for good
onshore wind sites close to demand centres in Europe
and North America growing, offshore wind has a vital
role to play in continuing the expansion of wind power
capacity, particularly in Europe.
Table 6.2: lcoe of wind aT differenT capaciTy facTors and discounT raTes
Capacity factor
25% 30% 35% 40% 45%
LCOE (2010 US cents per kWh)
Note: Assumes and installed capital cost of USD 1 950/kW and OM costs of USD 0.02/kWh that increase 1% per year for first ten years and then at 2%
per year.

24
22
20
18
16
14
10 30% 35% 40% 45% 50% 55% 60%
figure 6.9: The lcoe of wind for Typical offshore wind farms, 2011 To 2015
Capacity factor
offshore 2011 uSD 3750/kW
12

References
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Washington, D.C.
CanWEA (2010), 2010 CanWEA Small Wind Market Survey, Canadian Wind Energy Association,
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Acronyms
CAPEX Capital expenditure
CIF Cost, insurance and freight
DCF Discounted cash flow
FOB Free-on-board
GHG Greenhouse gas
GW Gigawatt
kW Kilowatt
kWh kilowatt hour
m/s metres per second
MW Megawatt
MWh Megawatt hour
LCOE Levelised cost of energy
OM Operating and maintenance
OPEX Operation and maintenance expenditure
RD Research and Development
USD United States dollar
WACC Weighted average cost of capital

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