Work Package 1 

Final Report 

IEA Wind Task 26
 

Multi-national Case Study of the 

Financial Cost of Wind Energy 

Leading Authors 

Paul Schwabe: National Renewable Energy Laboratory 

Sander Lensink: Energy Research Center of the Netherlands 

Maureen Hand: National Renewable Energy Laboratory 
 

 

 

IEA Wind Task 26 

Multi-national Case Study of
 

the Financial Cost of wind
 

Energy
 

Work Package 1
 

Lead Authors:
 

Paul Schwabe: National Renewable Energy Laboratory
 

Sander Lensink: Energy Research Centre of the Netherlands
 

Maureen Hand: National Renewable Energy Laboratory
 

Contributing Authors:

Athanasia Arapogianni: European Wind Energy Association 

Alberto Ceña: Spanish Wind Energy Association 

Karlynn Cory: National Renewable Energy Laboratory 

Markus Geissmann: Swiss Federal Office of Energy 

Klaus Hammes: Swedish Energy Agency 

Stefan Luxembourg: Energy Research Centre of the Netherlands

Ángeles Mora Sánchez: Spanish Wind Energy Association 

Edward James-Smith: Ea Energy Analyses 

Jan Wallasch: Deutsche WindGuard 

Paul Wilczek: European Wind Energy Association 

The IEA Wind agreement, also known as the Implementing
 

Agreement for cooperation in the Research, Development, and
 

Deployment of Wind Energy Systems, functions within a framework
 

created by the International Energy Agency (IEA). Views, findings, and 

publications of IEA Wind do not necessarily represent the views or 

policies of the IEA Secretariat or of all its individual member 

countries.
 

NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC. 

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Executive Summary 

The lifetime cost of wind energy is comprised of a number of components including the 

investment cost, operation and maintenance costs, financing costs, and annual energy production. 

Accurate representation of these cost streams is critical in estimating a wind plant’s cost of 

energy. Some of these cost streams will vary over the life of a given project. From the outset of 

project development, investors in wind energy have relatively certain knowledge of the plant’s 

lifetime cost of wind energy. This is because a wind energy project’s installed costs and mean 

wind speed are known early on, and wind generation generally has low variable operation and 

maintenance costs, zero fuel cost, and no carbon emissions cost. Despite these inherent 

characteristics, there are wide variations in the cost of wind energy internationally, which is the 

focus of this report. 

Using a multi-national case-study approach, this work seeks to understand the sources of wind 

energy cost differences among seven countries under International Energy Agency (IEA) Wind 

Task 26 – Cost of Wind Energy. The participating countries in this study include Denmark, 

Germany, the Netherlands, Spain, Sweden, Switzerland, and the United States. Due to data 

availability, onshore wind energy is the primary focus of this study, though a small sample of 

reported offshore cost data is also included. 

This report consists of two principal components. First, an overview and cross-country 

comparative analysis of the cost of wind energy is presented. The report then proceeds with a 

series of country-specific case studies that describe the unique cost elements of a typical wind 

energy facility in each of the represented countries. 

For this analysis, we considered the levelized cost of energy (LCOE) as the primary metric for 

describing and comparing wind energy costs from country to country. The LCOE represents the 

sum of all costs over the lifetime of a given wind project, discounted to present time, and 

levelized based on annual energy production. The LCOE does not include any residual costs or 

benefits incurred beyond the project’s assumed operational life. 

The levelized cost of energy may be calculated using several methods. This report summarizes 

two perspectives and approaches: a high level scenario planning approach and a sophisticated 

financial cash flow analysis approach. The majority of the analysis in this report, however, 

focuses on the financial cash flow analysis approach; thus, it represents the perspective of a 

private investor in a wind energy project in each of the participating countries. 

This analysis used a spreadsheet-based cash flow model developed by the Energy Research 

Centre of the Netherlands (ECN) to estimate the LCOE. The ECN model is a detailed discounted 

cash flow model used to represent the various cost structures in each of the participating 

countries from the perspective of a domestic financial investor in a wind energy project. The 

ECN model has been customized in this analysis to exclude country-specific wind energy 

incentives, resulting in unsubsidized LCOE estimates. 

iii 
 

 

 

 

 

 

 

Results of the analysis indicate that the unsubsidized LCOE varies considerably among countries 

represented in this study. As shown in Table ES-1, the country-specific LCOEs range from 

€61/MWh ($85/MWh) in Denmark to €120/MWh ($167/MWh) in Switzerland.1 

Table ES-1. 2008 Onshore LCOE by country 

LCOE 

€/MWh ($/MWh) 

Switzerland 120 (167) 

Netherlands 94 (131) 

Germany 85 (118) 

Spain 83 (115) 

Sweden 67 (93) 

United States 65 (91) 

Denmark 61 (85) 

The magnitude of the unsubsidized LCOE variation has been attributed to differences in countryspecific energy production, investment cost, operations cost, and financing cost. As expected, the 

largest LCOE impact from country to country was the anticipated energy production component 

that could be due to the inherent wind regime, site selection, wind turbine design, or other 

factors. Market forces such as electricity market structuring or the perception of risk in a wind 

project investment also impacted the LCOE through large variations in both capital expenditures 

and financing costs. Costs attributed to the operations of a wind project ranged broadly across 

countries and had a sizable LCOE impact as well, though caution with the reported data for 

operations and maintenance costs were common. The unique factors contributing to the 

variations in LCOE across countries are explored further in the comparative analysis and 

country-specific wind energy chapters of the report. 

Lastly, an alternative approach to calculating LCOE is also briefly explored. For example, highlevel planning scenarios may eschew a sophisticated discounted cash flow approach in favor of a 

simplified method to estimate LCOE. Under this simplified approach, assumptions for explicit 

financing terms and time-varying cash flows are not made, but instead a general discount rate is 

selected to represent all of the characteristics of the finance instrument. This more simplistic, 

high-level planning scenario approach minimizes the number of input parameters and the level of 

detail can facilitate LCOE comparisons among many different electric generation types. 

Therefore, the various methods in calculating LCOE require precise attention as to how, and 

from what perspective, the calculation is made, and comparisons should be made and interpreted 

carefully. 

1 Exchange rate of 1.39 USD/EUR is used in currency conversions. 

iv 
Table of Contents 

Chapter 1: Financial Cost of Wind Energy in Seven Countries ..................................................... 1
 

Chapter 2: Denmark...................................................................................................................... 23
 

Chapter 3: Germany...................................................................................................................... 40
 

Chapter 4: Netherlands ................................................................................................................. 50
 

Chapter 5: Spain............................................................................................................................ 59
 

Chapter 6: Sweden ........................................................................................................................ 72
 

Chapter 7: Switzerland.................................................................................................................. 81
 

Chapter 8: United States ............................................................................................................... 89
 

Appendix A – Glossary of Variables.......................................................................................... 104
 

v 
Table of Figures 

Figure 1-1. The cost of wind energy............................................................................................... 3
 

Figure 1-2. The cost of energy offset by revenues and incentives leaving only the financial gap. 7
 

Figure 1-3. Impact of country-specific energy production on the Reference Case ...................... 11
 

Figure 1-4. Impact of country-specific investment costs on the Reference Case......................... 12
 

Figure 1-5. Impact of country-specific O&M costs on the Reference Case................................. 12
 

Figure 1-6. Impact of country-specific financing costs on the Reference Case ........................... 13
 

Figure 1-7. Composite of country-specific costs on the Reference Case ..................................... 15
 

Figure 1-8. Key cost parameter’s LCOE impact across countries................................................ 16
 

Figure 2-1. Cumulative and annual Denmark wind installations ................................................. 24
 

Figure 2-2. Wind energy costs in Denmark and the Reference Case in 2008 .............................. 33
 

Figure 2-3. Illustration of Danish model for cost allocation of connection costs......................... 34
 

Figure 2-4. Danish revenues and wind energy policies and incentives in 2008........................... 36
 

Figure 3-1. Cumulative and annual wind installations in Germany ............................................. 40
 

Figure 3-2. Wind energy costs in Germany in 2008..................................................................... 46
 

Figure 3-3. Wind energy revenue and policy incentives in Germany (2008)............................... 47
 

Figure 4-1. Cumulative and annual wind installations in the Netherlands................................... 50
 

Figure 4-2. Graphical representation between the Netherlands and Reference Case ................... 55
 

Figure 4-3. Wind energy revenue and policy incentives in the Netherlands................................ 56
 

Figure 5-1. Cumulative and annual wind installations in Spain ................................................... 60
 

Figure 5-2. Evolution of the regulated tariff................................................................................. 61
 

Figure 5-3. Final retribution in the market option (market price plus premium) ......................... 62
 

Figure 5-4. Wind capacity on the wholesale market, 2008........................................................... 63
 

Figure 5-5. Year average of the daily electricity pool price and variation rate, 2003 – 2009 ...... 64
 

Figure 5-6. Size breakdown of wind turbines installed over 2008 ............................................... 65
 

Figure 5-7. Wind energy costs in Spain and the Reference Case in 2008.................................... 68
 

Figure 5-8. Revenues and wind energy policies and incentives in 2008...................................... 70
 

Figure 6-1. Cumulative and annual wind installations in Sweden................................................ 72
 

Figure 6-2. Wind energy costs in Sweden .................................................................................... 77
 

Figure 6-3. Wind energy revenue and policy incentives in Sweden............................................. 78
 

Figure 7-1. Cumulative and annual wind installations in Switzerland ......................................... 81
 

Figure 7-2. Wind energy costs in Switzerland compared to the Reference Case ......................... 85
 

Figure 7-3. Wind energy revenue and policy incentives in Switzerland ...................................... 86
 

Figure 8-1. Cumulative and annual U.S. wind installations ......................................................... 90
 

Figure 8-2. Wind energy costs in the U.S and the Reference Case in 2008 ................................. 98
 

Figure 8-3. U.S. revenues and wind energy policies and incentives in 2008 ............................. 100
 

vi 
 

 

 

Tables 

Table ES-1. 2008 Onshore LCOE by country ............................................................................... iv
 

Table 2-3. Relative values of 4 turbine models with varying hub heights, rotor diameters, and 

Table 2-4. Relative values of 4 turbine models with varying hub heights, rotor diameters, and 

Table 1-1. Cost elements of wind project capital investment......................................................... 2
 

Table 1-2. Onshore technical parameters by country and the Reference Case in 2008.................. 9
 

Table 1-3. Onshore financial parameters by country and the Reference Case in 2008................ 10
 

Table 1-4. 2008 Onshore LCOE and FG by country and the Reference Case ............................. 10
 

Table 1-5. Offshore technical parameters by project.................................................................... 17
 

Table 1-6. Offshore financial parameters by project .................................................................... 17
 

Table 1-7. Offshore LCOE and FG by project ............................................................................. 18
 

Table 1-8. Comparison of discount rate values and LCOE methodologies................................. 20
 

Table 2-1. Cumulative wind energy installations in Denmark (MW) .......................................... 25
 

Table 2-2. Annual wind energy installations in Denmark (MW) ................................................. 25
 

generator capacities before feed-in tariff based on full load hours............................................... 26
 

generator capacities including feed-in tariffs based on full load hours ........................................ 27
 

Table 2-5. Wind energy project features in Denmark................................................................... 31
 

Table 2-6. Wind energy financing terms in Denmark .................................................................. 31
 

Table 2-7. Wind energy revenue and policy incentives in Denmark............................................ 32
 

Table 2-8. Summary of levelized cost of electricity for Danish wind power in 2007 and 2008 .. 37
 

Table 3-1. Cumulative GW installed in Germany ........................................................................ 41
 

Table 3-2. Annual GW installed in Germany ............................................................................... 41
 

Table 3-3. Wind energy project features in Germany................................................................... 45
 

Table 3-4. Wind energy financing terms in Germany .................................................................. 45
 

Table 3-5. Wind energy policy and revenue incentives in Germany............................................ 45
 

Table 3-6. Summary of results for Germany ................................................................................ 48
 

Table 4-1. Cumulative GW installed in the Netherlands.............................................................. 51
 

Table 4-2. Net annual GW installed in the Netherlands ............................................................... 51
 

Table 4-3. Wind energy project features in the Netherlands ........................................................ 53
 

Table 4-4. Wind energy financing terms in the Netherlands........................................................ 53
 

Table 4-5. Wind energy policy and revenue incentives in the Netherlands ................................. 54
 

Table 4-6. Summary of results for the Netherlands...................................................................... 57
 

Table 5-1. Cumulative GW installed in Spain.............................................................................. 61
 

Table 5-2. Annual GW installed in Spain..................................................................................... 61
 

Table 5-3. Wind energy project features in Spain ........................................................................ 67
 

Table 5-4. Wind energy financing terms in Spain ........................................................................ 67
 

Table 5-5. Wind energy policy and revenue incentives in Spain ................................................. 67
 

Table 5-6. Summary of results for Spain...................................................................................... 70
 

Table 6-1. Cumulative MW installed in Sweden.......................................................................... 73
 

Table 6-2. Annual MW installed in Sweden................................................................................. 73
 

Table 6-3. Lillgrunden example.................................................................................................... 75
 

Table 6-4. Wind energy project features in Sweden..................................................................... 75
 

Table 6-5. Wind energy financing terms in Sweden..................................................................... 76
 

Table 6-6. Wind energy policy and revenue incentives in Sweden.............................................. 76
 

Table 6-7. Summary of results for Sweden .................................................................................. 79
 

Table 7-1. Cumulative MW installed in Switzerland ................................................................... 82
 

vii 
 

Table 7-2. Annual MW installed in Switzerland .......................................................................... 82
 

Table 7-3. Financing cost calculations.......................................................................................... 83
 

Table 7-4. Wind energy project features in Switzerland .............................................................. 84
 

Table 7-5. Wind energy financing terms in Switzerland .............................................................. 84
 

Table 7-6. Wind energy policy and revenue incentives in Switzerland ....................................... 84
 

Table 7-7. Summary of wind projects for Switzerland................................................................. 87
 

Table 8-1. U.S. cumulative wind energy installations (GW)........................................................ 91
 

Table 8-2. U.S. annual wind energy installations (GW)............................................................... 91
 

Table 8-3. Wind energy project features in the U.S. .................................................................... 96
 

Table 8-4. Wind energy financing terms in the U.S. .................................................................... 96
 

Table 8-5. Wind energy revenue and policy incentives in the U.S............................................... 97
 

Table 8-6. Summary of results for the United States.................................................................. 101
 

viii 
Chapter 1: Financial Cost of Wind Energy in Seven Countries 

Introduction 

In 2009, the European Union added 10,163 MW of new wind energy capacity while the United 

States added 9,994 MW (EWEA 2010, Wiser and Bolinger 2010). These capacity additions in 

2009 represented the largest source of new electricity generation in the EU and the second 

largest in the U.S. (EWEA 2010, Wiser and Bolinger 2010). Globally, demand for windgenerated electricity has increased for a number of reasons including growing concern for carbon 

emission mitigation, security and supply issues with fossil-based fuels, and a host other factors. 

The variability of the all-in cost of wind energy, however, may still be a barrier for increased 

deployment of wind energy across the globe. From the outset of project development, investors 

in wind energy have relatively certain knowledge of the plant’s lifetime cost of wind energy. 

This is because a wind energy project’s installed costs and mean wind speed are known early on, 

and wind generation generally has low variable costs, zero fuel cost, and no carbon emission 

costs. Even with these inherent characteristics, there are, however, wide variations in the cost of 

wind energy from project to project, within a country, and internationally. That is the focus of 

this effort. 

Objective and Approach 

Using a multi-national case-study approach, this work seeks to understand the source of wind 

energy cost differences across seven countries under International Energy Agency (IEA) Wind 

Task 26 – Cost of Wind Energy. The participating countries include Denmark, Germany, the 

Netherlands, Spain, Sweden, Switzerland, and the United States. 

Assessing the cost of wind energy requires evaluation of a number of components including 

investment cost, operation cost, finance cost, and annual energy production, and how these cost 

streams vary over the life of the project. Representation of each of the different temporal cost 

parameters as a single descriptive value may be accomplished using a variety of methods and 

approaches. For this project, we considered the levelized cost of energy (LCOE) as the primary 

metric for describing and comparing wind energy costs. The LCOE represents the sum of all 

costs over the lifetime of a given wind project, discounted to the present time, and levelized 

based on annual energy production. Furthermore, the LCOE can be calculated with a number of 

different methods or approaches to represent several differing perspectives. This report describes 

two of these perspectives and approaches - a high level scenario planning approach and a 

sophisticated financial cash flow analysis approach. 

The majority of the analysis in this report focuses on assessing the cost of wind-generated 

electricity, from the perspective of a private investor, in a given wind project, in each of the 

represented countries. More specifically, the LCOE analysis in this report represents the countryspecific financial cost of wind energy for a domestic investor financing their project using the 

adopted model and methodology. It is important to note that the financial cost comparisons are 

not a socio-economic cost evaluation of wind energy (i.e., the cost to society of this particular 

form of energy). 

When calculating the financial cost of wind energy, this analysis tabulates all of the expenditures 

required to install, operate, and finance a wind project. In addition to assessing the pure cost of 

1 
               

wind energy, this analysis also describes the revenues and wind energy incentives that are 

available to wind project owners in each of the represented countries. Differences that arise in 

cost elements among the countries are identified. 

This report begins with a brief description of the cost elements that comprise the levelized cost of 

energy. Then, the spreadsheet model developed under the auspices of this project is described. 

Based on the data provided by each represented country, a Reference Case is defined to provide 

a common point of comparison among countries. The cost elements from each country are 

compared to the Reference Case to identify the source of the differences in levelized cost of wind 

energy. The next section briefly identifies an alternative method, from the private investor 

perspective, to calculating levelized cost of wind energy. The report then presents different 

LCOE estimates, based on the cost elements defined in the Reference Case, to demonstrate the 

variability in LCOE associated with the different methods. Finally, each of the participating 

countries provided a chapter that summarizes the cost elements of a typical wind project in their 

country. These constitute the bulk of this report. 

Levelized Cost of Wind Energy 

Cost Elements 

The principal components of the cost of wind energy include capital investment, operation and 

maintenance, and finance. Within each category, a number of elements are included and 

Appendix A describes the individual cost elements considered in this report. 

Wind projects require a significant capital investment comprised of a number of other costs 

beyond the turbines alone. However, as shown in Table 1, approximately 75% of the total 

investment cost is associated with the cost of the wind turbines. Other costs include grid 

connection, foundations, installation, and construction-related expenses, summarized as 

percentages in Table 1-1. These are based on a selection of data from Germany, Denmark, Spain, 

and the UK. Decommissioning costs are set aside at the initiation of a project and these are 

included in the initial capital investment because they are required by some countries. 

Table 1­1. Cost elements of wind project capital investment

Share of 

total cost (%) 

Typical share of 

other cost (%) 

Turbine (ex works) 

Grid-connection 

Foundation

Electric installation 

Land 

Financial costs 

Road construction 

Consultancy 

68-84 

2-10 

1-9 

1-9 

1-5 

1-5 

1-5 

1-3 

-

35-45 

20-25 

10-15 

5-10 

5-10 

5-10 

5-10 

Source: The Economics of Wind Energy, EWEA Report 2009 

Operation and maintenance (O&M) costs contribute to the total cost of wind energy. A portion 

of these costs typically include fixed costs representing insurance, administration, and service 

contracts for scheduled maintenance. Variable O&M costs typically include scheduled and 

2 
unscheduled maintenance and component replacement. These costs vary from one year to 

another; therefore, estimates often are made by assuming a constant cash flow stream over the 

life of the project. Since wind projects do not require annual fuel expenditures, O&M costs 

constitute the majority of annual costs. In some electricity markets, operating costs associated 

with power system services, such as reactive power compensation, are required for wind 

projects. 

Finally, finance costs are a significant portion of the levelized cost of energy. The type of 

finance structures that are used to support construction of wind projects, and the associated levels 

of debt and equity contributors, vary among countries. The corresponding expected returns, by 

debt or equity investment providers, also vary significantly. In addition, each country’s 

corporate tax structure influences the total financial costs associated with wind projects. 

Figure 1-1 illustrates the various components included in an estimate of the cost of wind energy. 

The upfront investment costs, annual O&M costs, and financial variables are included. Because 

wind projects ultimately produce electricity, it is important to normalize the levelized cost with 

annual electricity production. Energy production depends on the wind turbines physical 

characteristics and the wind resource characteristics at a given project site. 

Source: The Economics of Wind Energy, EWEA Report 2009 

Figure 1-1. The cost of wind energy. 

Revenues and Incentives 

Electricity is the product sold by a wind project owner, and the markets for electricity vary by 

country. While this project focuses on the costs associated with generation of electricity from 

3 
wind power plants, the revenues and incentives in each of the electric markets represented are 

summarized. In addition to revenue from electricity sales, a variety of incentives are employed 

to assure that the costs of wind-generated electricity are recovered. These incentives include 

feed-in tariffs, production-based tax credits, renewable energy certificates, or other mechanisms. 

Externalities 

A number of aspects to wind-generated electricity are not currently monetized and thus, are not 

included in an assessment of revenues or cost. These externalities, or societal costs, are 

associated with secondary impacts from electricity generation technologies. In general, 

renewable technologies have very low external impacts compared to conventional generation 

technologies. The IEA Renewable Energy Costs and Benefits for Society (RECaBS) project 

estimates the costs and benefits of electricity generation from renewable sources compared to 

those of conventional generators using a transparent methodology (RECaBs 2007). According to 

the ReCABS methodology, the analysis includes five externalities: 

	 “Climate change; greenhouse gasses, in particular CO2 and CH4 

	 Other air pollutants: SOx, NOx, and particles 

	 Grid integration; primarily added costs to the electrical infrastructure including power 

balancing costs and reduced capacity value of wind turbines 

	 Security of fuel supply; substitution of fuel imports with indigenous resources. 

In addition to the externalities described above, electricity generation from wind does not rely on 

fuel consumption and the associated volatility of fuel prices. The investment risks for wind 

technology differ from the risk profile of fossil-fuel generation technologies. All of these 

characteristics create an important difference in the value proposition for wind technology 

relative to other generation technologies, but this study does not attempt to make such 

comparative assessments. 

LCOE Model Description 

The cash flow model developed by the Energy Research Centre of the Netherlands (ECN) forms 

the basis for the estimations of the LCOE and the financial gap (FG) for wind energy in this 

project. The ECN model is a discounted cash flow model, originally designed to calculate the 

feed-in premium subsidies for renewable electricity in the Netherlands. Currently, it is used by 

ECN to advise the Dutch government on the magnitude of the production costs for different 

renewable options. In the course of developing IEA Wind Task 26, the model has been tailored 

and extended to estimate cost structures in the participating countries. It is now a flexible, 

detailed tool for calculating the cost of wind energy. It contains modeling parameters such as unit 

size, operational time/full load hours, economic life, investment costs, O&M costs, project 

financing characteristics, and a wide range of additional relevant parameters. The model has 

been refined with more functionality and versatility when applying it to various countries and 

regulatory regimes, in general. For example, the revised cash flow model allows for adjustments 

to diverse technical and financial parameters, according to the respective regulatory regime of a 

wind power project. Such a flexible model is important, not only in the calculation of total 

investment costs, but also to account for the different operational features and financial 

instruments and incentives between countries and wind farms. 

4 
 

Basic Concept of the Model 

A high level of detail in calculating the cost of wind energy can be achieved using the cash flow 

spreadsheet model, with its full range of parameters detailed in Appendix A. This spreadsheet 

model consists of six different worksheets. The first three worksheets provide the detailed 

information needed to calculate the cost wind energy in a specific country. 

In the first worksheet, “Year-independent” variables can be set. These include project features, 

the total upfront investment costs, total decommissioning costs,2

 operational time in terms of full 

load hours, and the time horizon for the cost calculations. The investment and decommissioning 

costs can be given either as a total, or as a sum, of the various components. This is informative 

for cross-country comparisons of the differences in realized costs. In addition, a range of 

financial variables can be set in this worksheet. These include: inflation, to account for rising 

variable costs; return on debt; return on equity; and a debt/equity ratio, to reflect the financial 

risk associated with the project. Moreover, the cash flow model takes national and state corporate 

taxes into account. 

The “Year-dependent” worksheet contains multiple entries that constitute the fixed and variable 

annual costs including O&M, land rent, and grid-related costs. Again, the detailed subdivision 

allows for cross-country comparison. Definitions for the electricity price and small determining 

factors, like contract and balancing costs, are provided. 

In the third worksheet, labeled “Policies,” the applicable feed-in tariffs, tax credits, and other 

incentives are considered. As an option within the model, the benefits associated with tax breaks 

can be limited to the project’s cash flow or, alternatively, designated as unlimited.3 The input 

parameters are used to determine the LCOE of the wind energy project, and the financial gap 

(FG) of electricity production, in the subsequent worksheets. The “Input_Output” worksheet 

presents the resulting LCOE and FG. It summarizes the variables used in the calculation. The 

actual cash flow calculations take place in the “Project cashflow” and “LCOE cashflow” 

worksheets. 

LCOE and FG Calculations 

The LCOE and FG result from cash flow calculations made from the perspective of a private 

financial investor; thus, the nominal after-tax return on equity is used as a discount rate for both 

LCOE and FG. However, the LCOE and FG include different streams of cash flows for each 

calculation. These are briefly described below. 

LCOE is typically reported in terms of the investment outlays, annual costs, depreciation, and the 

chosen discount rate. Therefore, within this context, the LCOE calculation is defined as the 

production-dependent income required to achieve a zero net present value (NPV) of the equity 

share of the investment outlay, and the sum of all years’ discounted after-tax cash flows. In the 

LCOE calculation, the cash flows related to income, from electricity production and/or wind 

energy incentives specific to wind energy, are not taken into account. 

2

 In the subsequent analysis, decommissioning costs were included only if they were required by a particular country
 

to be set aside during project construction.

3

 In the subsequent analysis, all tax benefits were assumed to be “unlimited,” meaning that sufficient cash flow
 

exists to fully benefit from all available tax breaks. 

5 
 

The following formula is used in the ECN model’s calculation of LCOE: 

 ൌ ࡱࡻ࡯ࡸ

ሻ ܴ ݊ݎݑݐܱ݊݁ ݕݐ݅ݑݍܧ ൅ 1ሺ ௧ ௧ሻ݊݋݅ݐ݁ܿ݅ܽݎ݌݁ܦ ܽ݊݀ ݔܶܽ ௧ݐݏ݁ݎ݁ݐ݊ܫሺ ൈ ܶ ݔ݁ܽݐܴܽ െ ௧ሻ ݈ܽݐݑܱݏݕ ݑ݊݊ܣ݈ܽܯ&ܱ ሺ ൈ ሻ݁ݐ ܴ ܽ ݔܶܽെ1 ሺ

ሻ ܴ ݊ݎݑݐܱ݊݁ ݕݐ݅ݑݍܧ ൅ 1ሺ ௧ ሻ ܶ ݔ݁ܽݐܴܽ െ 1ሺ ൈ ௧ ݑ݀݋ݎܿ݁݀ܲ ݕݐ

ா௤௨௜௧௬ ்௢௧௔௟

ௌh௔௥௘ ൈ ூ௡௩௘௦௧௠௘௡௧ ൅ ∑்

௧ୀଵ 

்∑ ݑ݊݊ܣ݈݅ܿܽݎݐ݈݁ܿܧ ݅

௧ୀଵ 

Conversely, in the FG calculation, cash flows from electricity production and financial incentives 

specific to wind energy (e.g., soft loans, upfront cash, or tax-based investment subsides) are now 

considered. Under this definition, the FG effectively represents the difference between a 

country’s LCOE and the total realized income from the production of electricity and wind energy 

financial incentives. 

The following formula is used in the ECN model’s calculation of the FG: 

 ൌ ࡳࡲ

்௢௧௔௟

ூ௡௩௘௦௧௠௘௡௧ െ ∑்

ሻ ܴ ݊ݎݑݐܱ݊݁ ݕݐ݅ݑݍܧ ൅ 1ሺ ௧ ݓ݋݈ܨ݁ݐ݂ܣ ݎݏ݁ݔܶܽ ݄݈ܽݏܽܥ ݑ݊݊ܣ ௧ ௧ୀଵ

ா௤௨௜௧௬

ௌh௔௥௘ ൈ 

∑்

௧ୀଵ 

ሻ ܴ ݊ݎݑݐܱ݊݁ ݕݐ݅ݑݍܧ ൅ 1ሺ ௧ ሻ ܶ ݔ݁ܽݐܴܽ െ 1ሺ ൈ ௧ ݕݐ݅ܿ݅ݎ݀݋ݎܲ ܿ݁ݑ݀ ݈ܽݐ݈݁ܿܧ ݑ݊݊ܣ

As described above, Annual Cash Flow After Taxes includes revenue from electricity sales, 

wind energy subsidies, rebates and incentives, annual O&M costs, amortization of loans, interest 

payments, and the cash flows from the after-tax value of tax depreciation and interest deductions. 

Figure 1-2 illustrates the relation between the LCOE, the generated income (e.g., electricity 

market revenues, feed-in tariff, or feed-in premium), incentives, and the financial gap. As shown 

in Figure 1-2, the FG is defined such that a positive FG value corresponds to an insufficient 

amount of income necessary to cover the project developer’s LCOE. Conversely, a negative FG 

value implies that a sufficient amount of income is generated to cover the LCOE. 

6 
 

 

Wind energy subsidies, rebates, and incentives

 Feed-in tariff premium

 Electricity price 

LCOE 

Positive financial gap

 Feed-in tariff 

Negative financial gap 

Figure 1-2. The cost of energy offset by revenues and incentives leaving only the financial gap 

Cost of Onshore Wind Energy in Participating Countries 

The following section presents the country-specific financial cost of onshore wind energy for a 

domestic investor financing their project in each of the seven participating countries. This uses 

the ECN model and methodology. Cross-country comparisons of key onshore wind energy cost 

variables identify differences among each of the countries and offer a baseline onshore wind 

energy project cost. Due to limited available data, the cost of offshore wind energy is not 

presented in detail; however, a small sample of reported cost data is included. 

Limitations of Reported Data 

It is critical to note that, within this analysis, extensive efforts were made to verify the accuracy 

and validity of all collected wind energy costs, performance, and financial data. However, due to 

the numerous and diverse sources of data, the quality of the reported data varies among countries 

and sources. For example, reported cost data are intended to be presented in €2008, though in 

some instances, it is unclear whether they are presented in current or constant prices. Similarly, 

the parameters listed below are intended to be reflective of a wind project constructed in 2008; 

however, it is likely that some of the components were in fact ordered and paid for prior to 2008. 

Data limitations prevented correction of this possible discrepancy. Furthermore, while IEA Task 

26 aims to represent a “typical” project from each country, the actual cost of wind energy is site 

7 
 

 

 

and project specific. Therefore, the following data are presented as illustrative of overall countryspecific conditions only and should be considered with this in mind. 

Country-Specific Model Assumptions, LCOE, and the Reference Case 

The country-specific costs of wind energy are compared against a baseline project, herein 

referred to as the “Reference Case”. The Reference Case represents a composite of wind energy 

cost elements from each country. The cost elements in the Reference Case include both 

technical parameters (e.g., project features, performance, investment outlays, and 

decommissioning costs, operations and maintenance costs, and others), as well as, financial 

parameters (e.g., debt and equity shares, return on equity, debt interest rate, loan length, and 

national tax rate). The Reference Case does not include any revenue or wind energy policies or 

incentives due to each country’s unique approach in supporting wind energy. As such, only the 

LCOE calculation is presented for the Reference Case. 

The country-specific technical parameters are shown in Table 1-2.4

 For each technical 

parameter, the Reference Case value is calculated as the project-capacity weighted average 

across all countries. The technical parameter’s Reference Case values also are shown in Table 1­

2, and are heavily weighted towards Sweden and the United States due to their relatively large 

project capacities (98 and 85 MW respectively) in 2008. The Reference Case is weighted with 

project-capacity, instead of total domestic wind energy capacity, to illustrate a more or less 

typical project experienced in 2008 among each of the seven countries. While there are many 

differing options to construct the Reference Case project, it is important to point out that the 

choice of the Reference Case does not impact the country-specific LCOE or FG calculations. 

Simply, the Reference Case provides a general point for 2008 comparisons to present the 

country-specific results. 

4

 Note that the inputs for the modeling assumptions in Table 3 are shown in euros only; however, the LCOE and FG 

results are presented in both euros and U.S. dollars. 

8 
                          

         

       

         

         

         

         

     

         

         

       

 

 

 

 

Table 1­2. Onshore technical parameters by country and the Reference Case in 2008

Denmark 

2.3
 

7
 

2,695
 

1,250
 

0.0
 

3
 

0.00
 

12
 

12
 

6.1%
 

Germany 

2.0

5

2,260

1,373

1.5

0

46.33

0

21

3.8%

Spain 

2.0

15

2,150

1,250

0.0

3

0.00

20

20

11.4%

Unit size (MW)5 

Number of 

turbines 

Full load hours 

Investment6 

(€/kW) 

Decommissioning 

costs (€/kW) 

Other costs 

(€/MWh) 

O&M costs fixed 

(€/kW-yr) 

O&M costs 

variable (€/MWh) 

Converted total 

O&M costs 

(€/MWh) 

Reference Case 

Weight 

Netherlands 

3.0

5

2,200

1,325

0.0

10

31.39

13

28

5.7%

Sweden 

2.4

41

2,600

1,591

1.6

0

0.01

11

11

36.6%

Switzerland 

2.0

6

1,750

1,790

United 

States 

Reference 

Case 

2.1

34

2,628

1,449

0.0 0.6

0 1

0.00 6.29

31 11

31 13

4.6% N/A

1.7

50

3,066

1,377

0.0

0

8.60

5

7

31.8%

The country-specific financial parameters are shown in Table 1-3. For each financial parameter, 

the median value across all countries is used as the Reference Case value. As noted previously, 

the calculation of the Reference Case does not impact the country-specific LCOE or FG results. 

Although the ECN model uses the return on equity as the discount rate, the weighted average 

cost of capital (WACC) is also shown in Table 1-3 for illustrative purposes. The WACC 

incorporates several individual financial parameters (debt to equity ratio, return on equity, debt 

interest rate, and national tax rate) into a single metric descriptive of overall financing costs. 

5

 A more detailed cost of wind energy analysis also would include explicit assumptions pertaining to energy capture 

components, including rotor diameter, hub height, average wind speed and other significant parameters. The 

estimates included here are intended to be reflective of high level, simple specifications only, in part, to facilitate 

comparisons with other technologies and countries not represented here. 6

 As previously noted, the investment outlays and project construction are assumed to have occurred in 2008; 

however, it is likely that some of the investment outlays (e.g., ordering of the turbine) were in fact made prior to 

2008. 

9 
                           

 

 

 

 

 

 

             

                         

 

Table 1­3. Onshore financial parameters by country and the Reference Case in 2008

Return on debt 

(%) 

Denmark Germany Netherlands Spain Sweden Switzerland 

5.0 5.5 5.0 7.0 5.0 5.0 

Return on 

equity (%) 11.0 9.5 15.0 10.0 12.0 7.0 

70 

30 

20 

21.0 

4.9

Debt share (%) 80 70 80 80 87 

Equity share 

(%) 20 30 20 20 13 

Loan duration 

(yrs) 13 13 15 15 20 

National tax rate 

(%) 25.0 29.8 25.5 30.0 28.0 

WACC (%) 5.2 5.6 6.0 5.9 4.7

United Reference 

States Case 

6.0 5.0 

7.5
 10.0 

0 80

100 20

15
 15

38.9
 28.0 

7.5
 4.9

The country-specific LCOE and FG results are shown in Table 1-4 for each country and the 

Reference Case. The results include the 2008 levelized cost of energy and the financial gap 

calculation. While the results are intended to be illustrative of overall costs for onshore wind 

energy by country, the actual LCOEs for any wind project are site and project-specific. 

Table 1­4. 2008 Onshore LCOE and FG by country and the Reference Case

LCOE 

€/MWh ($/MWh) 

Financial Gap 

€/MWh ($/MWh) 

Switzerland 120(167) Germany 5 (7) 

Netherlands 94 (131) United States -1(-1) 

Germany 85 (118) Switzerland -1(-1) 

Spain 83 (115) Netherlands -3(-4) 

Sweden 67(93) Spain -3(-4) 

United States 65(91) Denmark -6(-8) 

Denmark 61 (85) Sweden -8(-11) 

Reference Case (68)95 Reference Case N/A 

As presented in Table 1-4, the LCOE by country ranges from €120/MWh ($167/MWh)7 in 

Switzerland to €61/MWh ($85/MWh) in Denmark. The Reference Case LCOE is estimated at 

€68/MWh ($95/MWh). The primary reasons for the variations of LCOEs across countries are 

due to differences in country-specific energy production, O&M expenditures, investment costs, 

and financing. The impact of these parameters on the country-specific LCOE is explored in the 

following section. 

Cross-Country LCOE Comparisons 

The cross-country analysis examined the LCOE impact of four key cost parameters between 

countries. For each country, the LCOE was estimated, with a single cost parameter set at a 

country-specific value, while all other parameters were set to the Reference Case value. The 

analysis isolated the impact of the country-specific input parameter compared to the baseline 

metric (the Reference Case parameter value). The key parameters tested in the cross-country 

7

 Exchange rate of 1.39 USD/EUR is used in currency conversions. 

10 
 

 

analysis included energy production, investment costs, operations and maintenance costs, and 

financing costs. The results were then compared across all countries. 

For example, the LCOE impact, of each country’s unique full load hours, is shown in Figure 1-3, 

which compares three distinct test cases. First, the grey bars show the unique country LCOE 

previously presented in Table 1-4, in which all input parameters are set to their country-specific 

values. Second, the blue line shows the baseline Reference Case LCOE at €68/MWh, in which 

all parameters are set to the Reference Case values. Third, the green circular markers show a 

mixed case, in which full load hours are set to the country-specific value while all other 

parameters are set to the Reference Case values. 

Figures 1-3 though 1-6 present this analysis of energy production (described above), investments 

costs, operations and maintenance costs, and financing costs, respectively. The country-specific 

LCOE (grey bars) and the Reference Case LCOE (blue line) are constant in each of the figures, 

while the key cost parameter is unique to each figure and is shown with distinct markers. 

0 

28 

56 

83 

111 

139 

167 

195 

20 

40 

60 

80 

100 

120 

140 

LCOE LCOE $/MWh 

€/MWh

Country Cost of Energy 

Reference Case with Country Energy Production 

Reference Case 

Switzerland

Hours: 1,750

Netherlands

2,200

Germany

2,260

Spain

2,150

Sweden 

2,600

United States

3,066

Denmark

2,695 

Figure 1-3. Impact of country-specific energy production on the Reference Case 

11 
 

 

Figure 1-4. Impact of country-specific investment costs on the Reference Case Switzerland €/MWh: 31 Netherlands 28 Germany 21Spain 20 Sweden 11 United States

7

Denmark 

12

0 

28 

56 

83 

111 

139 

167 

195 

20 

40 

60 

80 

100 

120 

140 

LCOE LCOE $/MWh 

€/MWh

Country Cost of Energy 

Reference Case with Country O&M 

Reference Case 

Switzerland

€/kW: 1,790

Netherlands

1,325

Germany

1,373

Spain

1,250

Sweden 

1,591

United States

1,377

Denmark

1,250

0 

28 

56 

83 

111 

139 

167 

195 

20 

40 

60 

80 

100 

120 

140 

LCOE LCOE $/MWh 

€/MWh

Country Cost of Energy 

Reference Case with Country Investment Costs 

Reference Case 

Figure 1-5. Impact of country-specific O&M costs on the Reference Case 

12 
 

0 

28 

56 

83 

111 

139 

167 

195 

20 

40 

60 

80 

100 

120 

140 

LCOE LCOE $/MWh 

€/MWh

Country Cost of Energy 

Reference Case with Country Financing 

Reference Case 

Switzerland

WACC: 4.9%

Netherlands

6.0%

Germany

5.6%

Spain

5.9%

Sweden 

4.7%

United States

7.5%

Denmark

5.2% 

Figure 1-6. Impact of country-specific financing costs on the Reference Case 

Some explanations for the variation in the key wind energy cost parameters across countries 

include, but are not limited to, the following: 

	 Energy Production (Full Load Hours): The variation of full load hours across countries is 

due to a number of common and independent factors. For example, in Germany, land 

constraints have pushed project development to southerly sites with poorer wind resources. 

In Denmark, spatial planning may promote repowering of existing wind sites ahead of 

expansion of undeveloped sites within the country. Consequently, some of the premier wind 

resource sites in Denmark were targeted in 2008 for repowering. In Switzerland, limited 

mountain accessibility has led to the development of just a few projects through 2008. In the 

United States, there are numerous project sites with sufficient to excellent wind resources; 

however, limited transmission access and availability have influenced project location 

decisions and, in some cases, forced the curtailment of energy output. Similarly, land 

constraints in Sweden are less of an issue than in other countries in the study. In the 

Netherlands, a feed-in-tariff premium, which is capped at a maximum amount of full load 

hours, may reduce the financial incentive to develop premier sites or utilize the most 

sophisticated technology. 

	 Investment Costs: Investment costs range significantly across countries. In both Denmark 

and the Netherlands, a feed-in tariff premium subsidy based on full load hours influences the 

choice of the wind turbine and, therefore, a project’s investment costs. In Denmark, 

preference may be given to turbines with large generators to maximize the value of the 

subsidy per full load hour, while in the Netherlands preference may given to less expensive 

13 
turbine technology since the subsidy is capped at maximum full load hours. In Denmark, 

some costs of installing a wind project, such as those interconnecting to the electric grid, are 

paid by the project’s end users (ratepayers) as opposed to the project’s developers. As such, 

interconnection costs are not included in Denmark’s investment costs. However, in Spain, 

Germany, and several other countries, interconnection costs and other grid reinforcement 

costs are paid for by the project developer and are included in investment costs. In Sweden, 

there is a simplified procedure for grid interconnection that may offer some investment cost 

savings. Germany's expansion of wind projects to southerly sites, with poorer wind 

resources, caused developers to compensate by constructing many of those projects at higher 

hub heights using larger rotor diameters (both of which are significant investment cost 

contributors). In Switzerland, difficulty accessing mountainous wind project sites, and the 

lack of economies of scale, have also contributed to high investment costs. 

In the United States, the cost-benefit of large project sizes is particularly applicable to the 

purchase of turbines, and there is evidence of price discounts as order size increases. The 

larger wind farm project sizes and less expensive investment costs in the United States, when 

compared to the Reference Case, suggest that the United States developers benefit from 

quantity discounts. Interestingly, Sweden does not benefit from a price reduction 

corresponding to large project size. This could be attributed to a smaller amount of total 

domestic installations in 2008 compared to the modeled project capacity. 

	 Operations and Maintenance Costs: Operations and maintenance cost data for each 

country were indicated as either highly uncertain or not readily available. In Denmark, 

creditors of wind projects typically require long-term O&M service contracts for 5-10 years. 

These were reported to cost approximately €25/kW annually. The Netherlands reported that 

their O&M costs typically also include a service contract that is priced consistently across 

projects, and a land-rent component, with a cost that varies significantly across projects, 

reportedly from €5/kW to €23/kW. Full service contracts often are required for a minimum 

of five years in Germany, as well. In Switzerland, limited O&M experience, high labor costs, 

accessibility difficulties, and turbine icing or turbulence may have led to higher O&M 

expenditures than in other countries. In the United States, O&M costs, on average, appear to 

be lower for projects installed more recently, and for larger project sizes. However, anecdotal 

evidence suggests that U.S. O&M cost estimates, including premature component 

replacements of gearboxes, blades, or generators, may be under-represented in the reported 

data. Germany also reported increased O&M expenditures for smaller projects due to the 

necessity of stocking replacement components. Moreover, Germany reported costly periodic 

site inspections as an important component of overall O&M costs. In Sweden, the spread of 

operations and maintenance costs varies widely by project developer. 

	 Financing Costs: The financing costs of onshore wind projects are similar across countries, 

with the exception of the United States. In Denmark, Germany, and the Netherlands, wind 

projects are typically project-financed, unless they are developed by a utility that finances 

wind projects on their balance sheets. In Denmark and Sweden, onshore wind projects are 

generally viewed as a low risk venture and finance pricing for onshore projects reflects this. 

In every country, except the United States, high debt ratios are utilized to finance a project, 

typically ranging from 60% to 87%. 

14 
 

 

 

The United States is a relative anomaly in the financing of wind projects. In 2008, many 

projects in the United States were financed with very high equity percentages (often 100%) 

and little to no project-based debt. This was due to federal tax subsidies that led to the 

proliferation of a specialized form of equity financing, known as tax equity. Because of the 

preference for tax equity financing, the cost of capital was generally higher in the United 

States than in other countries (i.e., tax equity is typically more expensive than debt). In 

instances in which debt financing was used to finance a project in the United States, the debt 

was often secured at the corporate-level instead of at the project-level. 

In summary, Figure 1-7 shows a composite of the four key cost elements shown in Figure 1-3 

through 1-6, as well as, the country-specific LCOE and the Reference Case LCOE. 

0 

28 

56 

83 

111 

139 

167 

195 

20 

40 

60 

80 

100 

120 

140 

LCOE €/MWh 

LCOE $/M Wh 

Country Cost of Energy RC with Country O&M 

RC with Country Energy Production RC with Country Financing 

RC with Country Investment Cost RC (Reference Case) Switzerland Netherlands Germany Spain Sweden United States

Denmark 

Figure 1-7. Composite of country-specific costs on the Reference Case 

To further illustrate the LCOE impact of key cost variables relative to other variables, Figure 1-8 

groups key cost parameters together, instead of delineating them by country. Figure 1-8 shows 

the impact of each country-specific cost variable, and the magnitude of increase or decrease in 

the country’s LCOE, when compared to the Reference Case. Red bars indicate country-specific 

values that increase the country’s LCOE, while green bars show country-specific values that 

decrease the country’s LCOE from the Reference Case. From top to bottom, the key cost 

parameters are listed by the magnitude of the LCOE increase above the Reference Case (red 

bars). For example, the smallest energy production variable, reported by Switzerland, increased 

the country’s LCOE by a greater amount than its O&M and investment costs. 

15 
 

When considering the spread, of country-specific input parameters, from lowest to highest, 

energy production and investment costs resulted in the largest LCOE impacts. This is generally 

consistent with previous wind LCOE sensitivity analyses (IEA 2010, Cory and Schwabe 2009). 

Interestingly, however, the range of reported O&M expenditures increased the LCOE estimates 

by a larger amount than the highest cost investment or financing expenditures, when comparing 

the Reference Case value to the highest-cost value. This could suggest that the uncertainty and 

availability of O&M data, and thus the wide range of country-specific input parameters, limits 

the precision of the LCOE estimate. Future analysis to reduce the differentials due to O&M 

expenditures may be needed. 

Figure 1-8. Key cost parameter’s LCOE impact across countries 

Cost of Offshore Wind Energy in Participating Countries 

In addition to onshore wind, the ECN model can estimate LCOE for offshore wind installations. 

At this time, however, very limited offshore data is available; particularly the full suite of input 

variables that are necessary to estimate country-specific LCOE. As such, cross-country LCOE 

comparisons for offshore wind are not made, nor is an offshore Reference Case constructed. 

Some reported cost and financing data are presented in Tables 1-5 and 1-6 below. It is important 

to note that, in Denmark, connecting to the grid and the necessity of a sea cable are socialized 

16 
              

 

 

 

 

           

       

              

 

 

 

 

 

 

costs and, therefore, not borne by the project developer. Because the model used in this analysis 

is from the perspective of the project developer, these costs are not captured in the Danish 

investment cost estimate. Although not used in the modeling analysis, the inclusion of these grid 

connection costs would increase the Danish investment cost estimate to approximately 

€3,000/kW. Table 1-7 shows the LCOE and financial gap estimated for these offshore wind 

energy projects. 

Table 1­5. Offshore technical parameters by project

2007 

Netherlands 

Prinses Amalia 

2008 

Denmark 

RØdsand II 

2008 

Germany 

Generic 

Project Status 2007 Cost

Projection

2008 Cost

Projection

2008 Cost

Projection

Year of completion 2007 Late 2010 Not Specified

Unit size (MW) 2.0 2.3 5.0

Number of turbines 60 90 12

Full load hours 3,350 3,800 3,700

Investment (€/kW) 3,315 1,883 3,230

Decommissioning 

costs (€/kW) 0 0 0

Other costs (€/MWh) 11 0 0

O&M costs fixed 

(€/kW) 149 0 123

O&M costs variable 

(€/MWh) 0 24 0

Converted Total 

O&M costs (€/MWh) 44 24 33

Economic life 15 25 20

Table 1­6. Offshore financial parameters by project

2007 

Netherlands 

Prinses Amalia 

2008 

Denmark 

RØdsand II 

2008 

Germany 

Generic 

Return on debt 

(%) 5.0 4.5 6.5

Return on 

equity (%) 12.0 11.2 15.0

Debt share (%) 50 26 70

Equity share 

(%) 50 74 30

Loan duration 

(yrs) 15 13 12

National tax 

rate (%) 25.5 25.0 29.8

WACC (%) 7.9 9.2 7.7

17 
               

 

 

Table 1­7. Offshore LCOE and FG by project

LCOE 

€/MWh ($/MWh) 

Financial Gap 

€/MWh ($/MWh) 

Prinses Amalia 166 (231) German Generic Projection N/A 

German Generic Projection 156 (217) RØdsand II Projection 6(8) 

RØdsand II Projection 88 (122) Prinses Amalia 5(7) 

Other Approaches to LCOE Calculation 

LCOE is calculated for a variety of purposes, motivations, and audiences. The general public, 

policymakers, investors, project developers, and others use LCOE for their particular needs. 

Therefore, each may utilize a different methodological approach. The level of detail, or the 

necessary assumptions, to estimate LCOE varies among methods and can have a significant 

impact on the LCOE outcome. Therefore, an alternative approach to calculating levelized cost of 

energy is described below, in contrast to the ECN model and methodology used thus far in the 

analysis. 

For example, high-level planning scenarios often estimate levelized cost of energy using a 

simplified representation that is based on the present values of the investment cost and the 

average annual costs discounted using a social discount rate. Under this approach, assumptions 

for explicit financing terms, such as debt to equity ratios, costs of debt and equity, loan duration, 

and corporate taxes, are not made. Instead, the simple approach relies on the value chosen for the 

discount rate, and this represents all of the characteristics of the finance instrument. The IEA 

“Projected Costs of Generation Electricity” (IEA 2010) and the “IEA World Energy Outlook 

2009” (IEA 2009) adopt this approach, and use the following equation to calculate the levelized 

cost of electricity: 

 =ࡱࡻ࡯ࡸ

ܦ ൅ ௧ ܽݎܾ݋݊ ܥ ൅ ௧ ݈݁ ݑܨ ൅ ௧ܯ &ܱ ൅ ௧ݐ݉݁݊ݐݏ݁ݒ݊ܫሺሺ ∑ ௧݊݅݊݃݋݅ݏݏ݉݉݅݋݁ܿ ሻ݁ݐܴܽ ݐ݊ݑ݋ܿݏ݅ܦ ൅ 1 ሺ כ ሻ ௧ି ሻ

௧ݕݐ݅ܿ݅ݎݐ݈݁ܿܧሺ∑ ሺ ሻ݁ݐܴܽ ݐ݊ݑ݋ܿݏ݅ܦ ൅ 1 ሺ כ ௧ି ሻሻ

௧ 

௧ 

Under this approach, IEA describes the discount rate as the “social resource cost,” which reflects 

the cost that society, as a whole, has to bear when investing in a specific technology (IEA 2010) 

From this social perspective, IEA uses a discount rate range from 5% to 10%, with 5% 

representing “a rate available to an investor with a low risk of default in a fairly stable 

environment” and 10% representing “the investment cost of an investor facing substantially 

greater financial, technological, and price risks” (IEA 2010). The more simplistic, high-level 

planning scenario minimizes the number of input parameters, and the level of detail facilitates 

LCOE comparisons among many different electric generation types. 

Conversely, sophisticated cash flow models, like the ECN model, are used by developers to 

evaluate specific projects, their LCOE, and a number of other financial metrics, such as net 

present value, internal rate of return, or payback period. These models often include several 

owners, a suite of explicit financing assumptions, tax impacts, and other revenue or cost 

influences. They are often structured to evaluate all likely cost streams and to solve for an 

energy price that provides a return large enough for a company to invest in a particular project 

18 
(Harper et al. 2007). Under this more detailed methodology, LCOE is impacted by numerous 

influences beyond the investment or annual costs. As the ultimate decision to build a project 

often rests with the investor, it is important to understand the investor perspective to understand 

the cost threshold that will allow wind capacity installations to continue. 

As an example, the ECN model used in this analysis is a sophisticated cash flow model that 

estimates a project-specific LCOE, while ensuring a pre-defined return on equity (ROE) to the 

equity investor. As described earlier, the additional detail in the ECN cash flow model allows 

the explicit representation of financing structures that have debt and equity interests. 

Representation of the cost of wind energy, from the perspective of the project developer, 

provides an estimate of the cost of wind generation that must be offset with income streams for a 

project to proceed. 

Comparison of Discount Rates on LCOE Calculation 

Table 1-8 shows a discount rate and LCOE methodology comparison. Using both the simple and 

the sophisticated cash flow analysis methods, the LCOE is estimated over a range of discount 

rates, while all other costs parameters were set to their Reference Case values. In addition, the 

discount rate value that yields the Reference Case LCOE (€68/MWh) is presented under both 

methods. 

The typical discount rate values selected to represent the perspective of the social investor tend 

to be lower than the corresponding values representing the private project developer or investor 

perspective. According to IEA 2010, the reason for using the lower discount rate in the social 

perspective is that public investors typically face lower financing costs and risks because the risk 

is spread over a large number of individuals instead of a smaller number of private investors. 

Correspondingly, the social perspective LCOE estimates also tend to be lower than the estimates 

for the private developer. 

19 
Table 1­8.  Comparison              of discount rate values and LCOE methodologies

Methodology & 

Perspective Perspective 

Treatment 

of 

Financing Application 

Discount 

Rate Range 

LCOE at 

Discount 

Rate 

Range* 

Discount 

Rate That 

Yields 

Reference 

Case LCOE 

Simple 

calculation for 

high-level 

scenario 

planning 

Public/Social 

investor 

perspective 

Implicit in 

discount 

rate 

IEA 2010 5% – 10% 

53 – 70 

€/MWh 

(IEA 

Method) 

9.5% 

(IEA 

Method) 

Sophisticated 

cash flow 

analysis 

Project 

developer or 

private 

investor 

Explicitly 

defined ECN 2008 

7.5% – 

15% 

(ROE)** 

64 – 76 

€/MWh 

(ECN 

Method) 

10% 

(ECN 

Method) 

*Using Reference Case assumptions for all other variables 

**Based on range of range of reported ROE’s from this analysis. 

As shown in Table 1-8, under both approaches, the difference in the selection of the discount rate 

impacts the LCOE value significantly. A discount rate of 9.5% is necessary to calculate the 

Reference Case LCOE of €68/MWh, using the simple calculation representing the social 

perspective. Therefore, based on the reported data by countries in this study, the discount rate 

should near the high end, 5-10% of values suggested in the IEA range of the simplified social 

planning method, to approximate the sophisticated cash flow approach. 

Conversely, the use of a lower discount rate (the low end of the suggested range) is used to 

represent the case of public investors. Therefore, when calculating the LCOE, and also when 

comparing the LCOE of wind energy to that of other generation sources, it is imperative that 

either the project developer perspective, or a broader utility or system-level perspective, is 

clearly identified. The selection of the discount rate value should correspond to the represented 

perspective. Utilization of various equations to represent LCOE requires clear interpretation of 

the perspective represented, the discount rate, and other parameter values chosen. 

Conclusions 

Results of IEA Wind Task 26 indicate that the LCOE varies considerably between countries. 

The magnitude of this variation has been attributed to energy production, investment cost, 

operations cost, and financing cost. As expected, the largest LCOE impacts, from country to 

country, were the anticipated energy production based on the inherent wind regime or wind 

turbine technology specifications. Market forces greatly impacted the overall cost of wind 

energy through large variations in both capital expenditures and differences in financing terms 

for a wind project. Costs attributed to the operation of a wind project ranged widely across 

countries and had a sizable LCOE impact. 

20 
 

The nature of LCOE, as a single overall metric descriptive of the cost of energy, allows for 

seemingly simple comparisons to be made across countries, purposes, audiences, and other uses. 

However, the various methods of calculating LCOE require careful attention to precisely how, 

and from what perspective, the calculation is made. LCOE is not a universal, interchangeable 

calculation. Rather, LCOE is an informative and useful tool that can be adapted to a particular 

need. Therefore, comparisons should be made and interpreted carefully. 

21 
References 

Cory and Schwabe, 2010. “Wind Levelized Cost of Energy: A Comparison of Technical and 

Financial Variables.” http://www.nrel.gov/docs/fy10osti/46671.pdf 

European Wind Energy Association (EWEA) (2009). “The Economics of Wind Energy A Report 

by the European Wind Energy Association.” March 2009. Available at 

http://www.ewea.org/fileadmin/ewea_documents/documents/publications/reports/Economics_of 

_Wind_Main_Report_FINAL-lr.pdf 

European Wind Energy Association (EWEA). (2010). “Wind in Power: 2009 European 

Statistics,” The European Wind Energy Association, February 2010. Accessed at 

http://www.ewea.org/fileadmin/ewea_documents/documents/statistics/100401_General_Stats_20 

09.pdf 

Harper, J.; Karcher, M.; Bolinger, M. (2007). “Wind Project Financing Structures: A Review and 

Comparative Analysis,” Ernest Orlando Lawrence Berkeley National Laboratory report LBNL63434, September 2007. Accessed at http://eetd.lbl.gov/ea/emp/reports/63434.pdf 

International Energy Agency (IEA). (2006). “World Energy Outlook: 2006” International Energy 

Agency. Accessed at http://www.iea.org/textbase/nppdf/free/2006/weo2006.pdf 

IEA. (2008), “World Energy Outlook: 2008” International Energy Agency. Accessed at 

http://www.iea.org/textbase/nppdf/free/2008/weo2008.pdf 

IEA. (2009), “World Energy Outlook: 2009” International Energy Agency. Accessed at 

http://www.iea.org/W/bookshop/add.aspx?id=388 

IEA. (2010), “Projected Costs of Generating Electricity” 2010 Edition.. Accessed at 

http://www.iea.org/publications/free_new_Desc.asp?PUBS_ID=2207 

RECaBs. (2007). “RECaBs Interactive Renewable Energy Calculator” Renewable Energy 

Calculator. Accessed August 2010, at http://www.recabs.org/ 

Wiser, R.; Bolinger, M. (2010). “2009 Wind Technologies Market Report,” U.S. Department of 

Energy, Office of Energy Efficiency and Renewable Energy, August 2010, at 

http://www1.eere.energy.gov/windandhydro/pdfs/2009_wind_technologies_market_report.pdf 

22 
Chapter 2: Denmark 

Overview of Wind Industry in Denmark 

The following chapter describes the project and cost characteristics of onshore and offshore wind 

energy in Denmark. It focuses on the assumptions used in modeling the levelized cost of energy 

(LCOE) for onshore and offshore wind technologies in 2008. 

Capacity, Energy Production, Near-Term Targets 

Total installed wind capacity in Denmark at the end of 2008 was 3,179 MW (2,756 MW onshore 

and 423 MW offshore). This is an increase of approximately 1.25% compared to the installed 

capacity at the end of 2007, and a 32% increase compared to the installed capacity in 2000. 

Approximately half of the increase in installed capacity from 2001 to 2008 occurred offshore. 

Three offshore wind farms were under construction in 2008, two were completed in 2009, and 

the third was expected to be commissioned in the fall of 2010. 

As shown in Figure 2-1 below, the rate of deployment was not evenly distributed throughout the 

period. A net increase of 725 MW of installed capacity was achieved from 2001 to 2003, while 

installed capacity only increased by 8 MW from 2004 to 2007. This was a result of a dramatic 

reduction in the financial support program for onshore deployment that took effect in 2003. A 

new feed-in tariff supplement introduced in 2008 resulted in renewed interest in erecting onshore 

turbines. Since its introduction in 2008, a net increase of 280 MW of onshore capacity was 

achieved by the end of July 2010 (Danish Wind Industry Association, 2010). 

In 2008, wind power production in Denmark supplied approximately 20% of the total electricity 

consumption. 

23 
-200 

0 

200 

400 

600 

800 

1,000 

-1,000 

0 

1,000 

2,000 

3,000 

4,000 

5,000 

Annual Capacity (MW) 

Cummulative Capacity (MW) 

Cumulative Offshore (left axis) 

Cumulative Onshore (left axis) 

Total Annual CapacityAdditions (right axis) 

Installed

Before 2000

200020012002200320042005200620072008

2012

Projection

2020

Projection 

Source: Danish Wind Industry Association 2010 and European Commission 2010 

Figure 2-1. Cumulative and annual Denmark wind installations 

Denmark does not have annual targets for wind power deployment. EU requirements have, 

however, necessitated that Denmark produce a plan for achieving a target of 30% of total energy 

consumption, including the transportation sector, from renewable sources by 2020. EU 

regulations require that each member state produce an action plan for achieving the RE target. 

Denmark published its national action plan in June 2010. The plan estimates that wind power 

production in 2020 will be 11,000 GWh from approximately 4 GW of installed capacity. One 

third of total capacity, and approximately 50% of production, is expected to be from offshore 

turbines (Kemin 2010). Production in 2009 was approximately 6,700 GWh. The wind energy 

capacity projections in 2012 and 2020 are from the National Renewable Energy Action Plans 

(NREAP) of the European Member States (European Commission 2010). 

Short term goals include adding 800 MW of offshore capacity between 2008 and 2012, and 350 

MW of new onshore capacity. Half of the target must be achieved through repowering, which 

will result in a cumulative increase of 175 MW. Local planning authorities must have planning 

provisions in place to add 150 MW of onshore capacity, above the 350 MW, by 2012. 

The short term target of 800 MW for offshore wind is expected to be achieved through the 

commissioning of three large offshore wind farms; Horns Rev II (209 MW, commissioned in 

September 2009), Rødsand II (207 MW, planned for autumn 2010) and Anholt (400 MW, 

planned for December 2012). 

24 
                 

 

 

                 

 

 

 

 

 

Table 2-1 presents historical and projected cumulative wind energy installed in Denmark 

Table 2­1. Cumulative wind energy installations in Denmark (MW)

Installed 

Before Projection Projection 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2012 2020 

Onshore 1,761 2,358 2,464 2,697 2,708 2,716 2,720 2,728 2,717 2,756 2,985 2,621 

Offshore 11 50 50 210 423 423 423 423 423 423 856 1,339 

Source: Danish Wind Industry Association 2010 and European Commission 2010 

Table 2-2 shows historical and projected annual capacity additions. 

Table 2­2. Annual wind energy installations in Denmark (MW)

Installed 

Before 2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 

Projection 

2012 

Projection 

2020 

Onshore 1,761 597 106 183 12 8 4 8 -11 39 -38 -135 

Offshore 11 39 0 210 223 0 0 0 0 0 100 -14 

Source: Danish Wind Industry Association 2010 and European Commission 2010 

Revenue and Policy Incentives 

The renewable energy law of 2008 introduced a new remuneration system for wind power 

projects. All new onshore wind power projects and open door offshore projects8 receive a price 

supplement of DKK 0.25/kWh (€0.034/kWh9

) ($0.047/kWh) over and above the spot market 

price for the first 22,000 full load hours10. Once this is reached, wind power projects receive the 

market price for power. 

Wind turbines receive an additional subsidy of DKK 0.0237/kWh (€0.0037/kWh) ($0.005/kWh) 

for the technical lifetime of the project to cover balancing costs. 

It generally takes between 7 and 10 years for a wind turbine to produce the equivalent of 22,000 

full load hours in Denmark. 

If, for example, a 3 MW turbine is erected, the feed-in tariff is determined as follows:11 

1 full load hour for a 3 MW turbine ൌ 3,000 kWh 

 3,000 ܹ݇h ൈ 22,000 ൌ66 ܩܹh

The feed-in tariff and the balancing subsidy are paid for the first 66 GWh of production for a 3 

MW turbine. 

8

 Open door projects are defined as offshore projects built outside of the public bidding process for offshore wind
 

power plants. One offshore power plant has been built using the open door application process. 9 1 Euro = 7.353 Danish Krone
 10 The current price supplement replaced a program whereby wind projects received DKK 0.10/kWh (€0.013/kWh) 11 The following example is not included in other country chapters, therefore is reported in Danish Kroner. 

25 
 

                             

                   

   

       

     

     

     

     

 

 

This has a value of: 

ሺ 66 GWh ൈ 0.25krሻ ൅ ሺ66 GWh ൈ 0.0237krሻ ൌ ܭܭܦ 18,064,200 

A repowering subsidy is also available for new wind power projects that decommission older 

turbines. The subsidy is DKK 0.08/kWh(€0.01/kWh)($0.0139) for 12,000 full load hours for 

double the decommissioned capacity. If, for example, a 225 kW wind turbine is purchased and 

decommissioned by a new project development, then the repowering subsidy is calculated as 

follows: 

1 full load hour f or a 225 ܹ݇ ൈ 2 ൌ 450 ܹ݇h

 450 ܹ݇h ൈ 12,000 ൌ 5.4 GWh 

The repowering subsidy for a decommissioned 225 kW turbine has a value of 

 432,000 ܭܭܦൌ ݎ0.08݇ ൈ hܹܩ 5.4 

This subsidy applies only for decommissioned turbines under 450 kW. There is no limit to the 

number of turbines a new project can decommission to benefit from the repowering subsidy, but 

the subsidy is only available for the decommissioning of a total of 175 MW of turbines under 

450 kW. 

A feed-in tariff based on full load hours, rather than a uniform number of kilowatt hours 

produced, generally favors investments in turbines with larger generators rather than those with 

higher hub heights and larger rotors. A 3 MW generator, for example, will produce twice the 

amount of kilowatt hours per full load hour than a 1.5 MW turbine will produce and therefore, it 

would receive double the subsidy. 

The influence a feed-in tariff has on the choice of turbine for a wind project is illustrated in 

Tables 2-3 and 2-4 below. The examples are taken from an actual project. 

Table 2­3. Relative values of 4 turbine models with varying hub heights, rotor diameters, and

generator capacities before feed­in tariff based on full load hours12

Generator

size, MW

Rotor Hub

Height

Annual

production,

MWh

Project

cost/

turbine,

MDKK

Value of

power

sales,

MDKK

Income/

investment

Relative

value

3,0 90 80 7,089 22.2 49.6 2.23 0.98

3,0 90 90 7,497 23.43 52.5 2.24 0.99

3,0 112 94 10,384 32.6 72.7 223 0.98

1,8 90 80 6,047 18.6 42.3 227 1.00

(Nielsen et al. 2010) 

12 The following example is not included in other country chapters; therefore, it is reported in Danish Kroner. 

26 
                             

                   

   

           

     

     

     

     

Table 2­4. Relative values of 4 turbine models with varying hub heights, rotor diameters, and

generator capacities including feed­in tariffs based on full load hours

Generator

size, MW

Rotor Hub

Height

Annual

production,

MWh

Project

cost/

turbine,

MDKK

Value of

power

sales,

MDKK

Value of

subsidy,

MDKK

Total

income,

MDKK

Income/

investment

Relative

value

3.0 90 80 7,089 22.2 49.6 16.5 66.1 2.98 1.00

3.0 90 90 7,497 23.43 52.5 16.5 69.0 2.95 0.99

3.0 112 94 10,384 32.6 72.7 16.5 89.2 2.73 0.92

1.8 90 80 6,047 18.6 42.3 9.9 52.2 2.81 0.94

 (Nielsen et al. 2010) 

The example above indicates how a feed-in tariff that is based on full load hours favors 

investments in large generators rather than large rotors and higher towers. In Table 2-3, the most 

economically efficient turbine is the smaller 1.8 MW, with a large rotor. This also would be the 

case if the feed-in tariff was based on a uniform number of kilowatt hours produced for all 

turbines. In Table 2-4, the additional income from the feed-in tariff, based on full load hours, 

favors the 3 MW generator with the smaller rotor and lower hub height, while the smaller 

generator is relegated to third. 

The advantage of using full load hours as the basis for a feed-in tariff is that it results in fewer 

turbines being built to achieve a prescribed level of installed capacity. It also reduces the benefits 

of larger rotors and higher hub heights. These two issues can often be problematic in spatial 

planning and local acceptance of projects. Feed-in tariffs based on full load hours will favor 

achieving a political target based on installed capacity deployed, such as the short term target for 

wind power deployment in Denmark. 

The disadvantage of basing the feed-in tariff on full load hours is that the most economically 

efficient turbines are not necessarily the most attractive for project developers because the 

subsidy distorts the market. This can ultimately result in wind power being more expensive than 

it would be otherwise. This form of feed-in tariff used in Denmark ultimately increases the costs 

associated with achieving production-based targets. 

Typical Wind Energy Project in Denmark in 2008 

The following section describes 2008 wind power project characteristics in Denmark. The data is 

based on an average for projects planned or commissioned in 2008. The investment costs for 

onshore turbines vary according to site conditions, yet production costs in Denmark appear to be 

relatively uniform. Investment costs per installed MW can vary by up to 50%, while investment 

costs per MWh of production in the first year generally vary by less than 15%. 

27 
 

Onshore 

Project Features 

Onshore wind projects in Denmark are generally in the form of small clusters ranging from 3 to 

12 turbines. Planning guidelines recommend that wind power projects should be erected in 

clusters of at least three turbines arranged in a straight line or a gentle curve to avoid the 

prevalence of single turbines scattered throughout the landscape and reduce visual impact. There 

are a few examples of larger onshore wind farms in Denmark, but relative to Spain and the 

United States, they are very small. The largest is 20 turbines with a total capacity of 63 MW. 

The average size of turbines installed in 2008 was 1.9 MW, with a rotor diameter of 80m, and a 

hub height of 72m. The most common turbine installed in 2008 was a 2.3 MW generator, with a 

hub height of 80m and a rotor diameter of 93m. 

Project Performance 

The prevailing wind direction in Denmark is westerly, which makes sites along the North Sea 

coast the most attractive for wind turbines. Even though wind resources generally decline as one 

moves eastwards, most coastal and near coastal sites have an average annual wind speed above 7 

meters per second (m/s). This equates to approximately 2,500 full load hours for a 2 MW 

turbine, with a hub height of 80m (Danish Energy Agency, 2010). The average number of full 

load hours in 2009, for turbines installed in 2008, was 2,639. The 2009 wind resource in 

Denmark was 88% of a normal year, indicating that the lifetime average number of full load 

hours for turbines installed in 2008 is expected to be approximately 3,000. It is important to note 

that the estimated full load hours are based on projects installed in 2008 that operated during 

2009 – and not on total Danish wind resource potential. 

Investment Costs 

Typical project investment costs ranged from €1,100/kW ($1,529/kW) to €1,300/kW 

($1,807/kW) in 2008 with an average of €1,250/kW ($1,738/kW). There are indications that 

prices peaked in 2008 and have reduced substantially in 2009 and 2010 (Nielsen et al. 2010). 

Operations and Maintenance Costs 

There are four major cost components of operation and maintenance (O&M) for wind turbines in 

Denmark: insurance, repair, service agreement, and land rent/administration. Each cost 

component accounts for approximately 25% of O&M costs over the lifetime of a wind power 

plant. The expected lifetime costs for O&M for a wind project built in 2008 are €12/MWh 

($17/MWh) (Nielsen et al. 2010). 

Financing Costs 

The model uses project financing with 80% annuity-based debt. Privately owned wind turbines 

in Denmark are generally financed with an overdraft facility. All income is placed in the 

overdraft facility and the wind turbine owners do not have direct access to the funds. All 

expenditure and payment of returns on investments must be approved by the creditor. 

Good projects can be 100% debt financed in Denmark, but it is the norm that projects are 

approximately 80% debt financed. An acceptable payback time on loans to onshore wind 

projects is no more than 15 years. 

28 
 

 

The interest rate in 2008 on overdraft facilities for onshore wind power projects was 

approximately 5% fixed for 5 years. Interest rates for onshore wind power projects are generally 

low compared to many other business ventures because they are considered to have good 

liquidity. Wind turbines are considered low risk ventures as there are good facilities available for 

managing risk factors in wind power projects. 

An equity rate of between 9 and 11% is normal for new onshore projects in Denmark. This 

allows for a risk premium of between 5 and 7%. This again represents the relatively low risk in 

onshore power projects when compared to the average risk premium on the OMX 20 on the 

Danish stock exchange, from 1983 to 2002, which was 7.2%13 (Saabye, 2003). 

Revenues and Incentives 

The main sources of revenue from onshore wind turbines are the sale of power through Nord 

Pool and a price supplement subsidy in the form of a feed-in tariff. Onshore turbines can enter 

into fixed price agreements with balancing agents for up to five years14. These fixed price 

agreements are set according to the forward market on Nord Pool. 

Source of Data 

Data is sourced from the publication, Economy of Wind Turbines, Nielsen et al. 2010 and 

interviews with banks and project developers. 

Offshore 

Project Features 

No offshore projects were commissioned in Denmark in 2008, but three were either in the 

planning or construction phases. 

Offshore wind farms are generally developed through government concessions that are awarded 

on the basis of a bidding process. The lowest price per kWh bid for the first 50,000 full load 

hours of production is awarded the concession. After the first 50,000 full load hours, the wind 

farm sells its power on the open market. Horns Rev I and II and Rødsand I and II were awarded 

using a bidding process. A bidding round for a new offshore wind farm near Anholt was 

completed in June 2010. It has a capacity of 400 MW and must be in production by December 

31, 2012. 

“Open door”15 wind farms are also permitted. If approval is granted to build an “open door” 

wind farm, then the same incentive program for land based wind turbines applies. Two “open 

door” wind farms have been built to date. 

Investment Costs 

The investment costs for developers of offshore wind farms in Denmark are approximately 

€2,700/kW to €3,000/kW ($3,753 to $4,170/kW) for large wind farms of approximately 200 

MW under the concessionary bidding process. 

13 Saabye, N., Risikopræmie på aktier, 2003, National Bank of Denmark 14 New products are appearing, offering fixed prices for 10 years. 15 Open door projects are defined as offshore projects built outside of the public bidding process for offshore wind 

power plants. In addition to the two wind farms, one offshore power plant has been built using the open door 

application process. 

29 
 

 

The cost of connecting concessionary offshore wind farms to the national power grid and the 

transformer platform are socialized in Denmark, which reduces the total investment for project 

developers. Costs for performing environmental impact assessments and preliminary geological 

assessments of the seabed are also socialized. 

Operations and Maintenance Costs 

Operational costs for offshore wind farms are uncertain due to the limited statistical data and the 

steep experience curve for operating offshore wind parks. Average operating and maintenance 

costs over the lifetime of large offshore wind farms in Denmark range from €18/MWh 

($25/MWh) to €20/MWh ($28/MWh) depending on local conditions. 

Financing Costs 

Large offshore wind farms in Denmark are financed over the balance books of the project 

developers. Loans from the Nordic Investment Bank have been utilized for all the concessionary 

offshore farms, though not in the form of project financing. Concessionary offshore wind farms 

are typically financed with an equity share above 50%. 

The cost of equity for utilities in Denmark has been calculated at approximately 11.2%, while the 

cost of debt is between 4.5 and 5.5% (Nielsen et al. 2010). 

Revenues and Incentives 

Concessionary offshore wind farms receive a fixed price for power produced for the first 50,000 

full load hours. The fixed price is determined in the bidding process. The bid price is not index 

regulated; it is determined after the first 50,000 full load hour revenues have occurred from sales 

through the Nord Pool power exchange. The winning bid price for Horns Rev II was 

€0.069/kWh ($0.096/kWh) and for Rødsand II €0.085/kWh ($0.118/kWh). A price supplement 

to the market price is provided by the system operator to meet the bid price. If the market price is 

higher than the bid price, the wind farm must pay the difference to the system operator. 

Non-concessionary or “open door” offshore wind farms receive €0.034/kWh ($0.047/kWh) for 

the first 22,000 full load hours as well as the other available subsidies for onshore turbines. 

Source of Data 

The data on the total costs of building Horns Rev II and Rødsand II are derived from publicly 

available information, interviews with experts on developing offshore wind farms in Denmark, 

interviews with offshore wind owners, interviews with financiers of offshore wind farms, and 

calculations based on bid prices. 

Model Input Assumptions 

The following tables outline the modeling assumptions used for onshore and offshore wind 

energy in Denmark. 

30 
                 

 

 

 

 

 

               

 

 

 

 

 

 

 

 

 

Table 2­5. Wind energy project features in Denmark

Onshore Onshore Offshore Offshore 

200716 2008 200717 200818 

Unit size MW - 2.3 2.3 2.3 

Number of turbines N - 3 91 90 

Production Full load hours - 2,700 4,300 3,865 

Economic life Years - 20 25 25 

Investment costs €/kW ($/kW) - 1,250 

(1,738) 

2,844 

(3,953) 

3,000 

(4,170) 

O&M costs fixed €/kW ($/kW) - - - -

O&M costs variable €/MWh ($/MWh) - 12 (17) 20 (28) 18 (25) 

Decommissioning costs €/kW ($/kW) - - - -

Other costs €/MWh ($/MWh) - 3(4) - -

Source: Economics of Wind Turbines, Nielsen et al. 2010 

Table 2­6. Wind energy financing terms in Denmark

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Return on debt % - 5.0% 5.5% 4.5% 

Return on equity % - 11.0% 11.2% 11.2% 

Debt share % - 80% 45% 26% 

Equity share % - 20% 66% 74% 

WACC % - 5.2% 8.8% 9.5% 

Loan duration Years - 13 10 13 

Corporate tax rate % - 25% 25% 25% 

FX rate USD/€ 1.39 1.39 1.39 

FX rate DKK/€ - 7.353 - 7.353 

Sources: Nielsen et al. 2010, interviews with banks and export credit funds. 

16 No new wind turbines were erected in Denmark in 2007 17 No offshore turbines were built in 2007 or 2008. There were, however, 3 offshore farms either under construction 

or in the planning phase. Two of the farms fell under the government concessionary program, while the third was an 

“open door” project. The final investment decision was made for Horns Rev II in 2007; therefore, the figures are 

based on estimated costs for Horns Rev II. The investment decision for Rødsand II was made in 2008 and this 

provides the basis for costs in that year. 

18 The example used here is calculated from the bid price for Rødsand II as the construction agreements were 

entered into in 2008. 

31 
                    

 

 

 

 

 

 

 

 

Table 2­7. Wind energy revenue and policy incentives in Denmark

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Market price electricity €/MWh ($/MWh) - 44.7 (62.1) 28 (39) 44.7 (62.1) 

Market price certificates €/MWh ($/MWh) - N/A - N/A 

FIT revenue €/MWh ($/MWh) - 37 (51) 70 (97) 85 (118) 

FIT policy period Full load hours - 22,000 50,000 50,000 

Upfront tax-based subsidy before tax % - N/A N/A N/A 

Production-based after tax credits €/MWh ($/MWh) - N/A N/A N/A 

Production-based after tax credit 

 policy period €/MWh ($/MWh) - N/A N/A N/A 

Depreciation period Years - Max. 25% 

annually 

Max. 25% 

annually 

Max. 25% 

annually 

Reactive power bonus €/MWh - N/A N/A N/A 

Low voltage ride through bonus €/MWh - N/A N/A N/A 

Sources: Nielsen et al. 2010, Danish Energy Agency 2008, Danish Energy Agency 2009 

Cost of Wind Energy Generation 

Cost Comparison 

The data for wind power investments in Denmark in 2008 was used to calculate the levelized 

cost of energy and compare it to the Reference Case LCOE presented in Chapter 1. The 

Reference Case is a representative wind power project for all participating countries in Wind 

Task 26. 

The impacts of six variables in the Reference Case are compared with the Danish case to identify 

how each variable influences the levelized cost of wind power in Denmark. The comparison 

between the Reference Case and the Danish case is shown in Figure 2-2 below. The LCOE for an 

average project in Denmark was €61 ($85) in 2008, which is €7 ($10) lower than the Reference 

Case LCOE at €68/MWh. 

32 
 

 

   

         

         

€68 ($95)

€61 ($85)

€1 ($1)

€7 ($10)

€3 ($4) €1 ($1)

€1 ($1)

70

75

81

86

92

97

103

50

54

58

62

66

70

74

LCOE (2008 $/MWh)LCOE (2008 €/MWh)

Decreases LCOE FromReference Case LCOE

Increases LCOE FromReferenceCase LCOE

ReferenceCase LCOE

Project output

Total investment

&

decommissioning costs

Financing costs

Annual operations

&

maintenance costs

Other costs

Non‐Wind energy

related policies

Denmark LCOE

Country‐Specific InputVariables

Figure 2-2. Wind energy costs in Denmark and the Reference Case in 200819 

Project Output 

The project output in the Reference Case is a little over 2,600 full load hours, while the average 

production in 2009 for Danish projects commissioned in 2008 was slightly below 2,700 full load 

hours because 2009 was a poor wind year, with only 88% of the wind energy compared to an 

average year. If this is taken into account, then the average project for 2008 had approximately 

3,000 full load hours annually, which improved the economy of the project and resulted in a 

reduction in the LCOE by approximately €5($7). 

The higher number of full load hours for the Danish case, compared to the Reference Case, 

decreased the Danish LCOE by €1($1) per MWh. 

Total Investment Costs 

Investment costs in Denmark in 2008 were approximately €200/kW ($278/kW) lower than in the 

Reference Case. The major reason for project costs being 15% lower in Denmark is that grid 

connection costs in Denmark are paid by the grid company. 

The grid company pays connection costs from the point of coupling to the grid. This includes 

costs for substations and transformers. The project owner pays for costs from the turbine to the 

coupling point. If an area is identified as a wind turbine area in spatial planning regulations, then 

19 Data labels are rounded to nearest whole numbers. Therefore, the sum of input variables may differ slightly from 

the total Reference Case – Country LCOE differential (due to rounding). 

33 
 

the responsible grid company must extend the grid to allow for connection at this point. This 

must be done at the expense of the grid company. This regulation can reduce overall project 

costs substantially and is illustrated in Figure 2-3 below. 

Wind power 

project 

Existing grid 

infrastructure 

New connection line 

Paid for by grid company 

Paid for by 

project 

Figure 2-3. Illustration of Danish model for cost allocation of connection costs 

Other factors that may reduce investment costs compared to the Reference Case are the favorable 

geological conditions for constructing foundations, the existence of a strong, local turbine 

manufacturing industry, an experienced project development sector, and well developed 

regulation for wind turbines in spatial planning and environmental impact assessments. 

Financing Costs 

Financing costs in Denmark are more expensive than in the Reference Case. The required return 

on equity in Danish projects was 11.0% compared to 10.0%, and the average interest rate on debt 

for wind power projects was the same ratio as debt financing when compared with the Reference 

Case. 

The interest rate on debt in Danish projects is an expression of the perceived low levels of risk 

associated with financing wind turbines due to their good liquidity in Denmark and the market 

availability of efficient risk management products for wind power projects. The higher cost of 

equity in Denmark is a result of a higher exposure to price risk on the power market since the 

feed-in tariff supplements the market price, rather than guaranteeing remuneration, which occurs 

in most other countries with feed-in tariffs. There are no support schemes available for soft loans 

etc. in Denmark that can reduce financial costs. 

Financing costs increase the LCOE in Denmark by approximately €3 ($4) compared to the 

Reference Case. 

Operations and Maintenance Costs 

Operation and maintenance costs in Denmark are only represented as a variable cost. A 

comprehensive study, in 2009 and 2010 (Nelson et al, 2010), indicated that operation and 

maintenance costs for turbines erected in 2008 would be approximately €12/MWh ($17/MWh) 

over the project’s technical lifetime. 

Operation and maintenance costs reduce the LCOE for Danish projects by 1€ ($1) relative to the 

Reference Case. 

34 
Other Costs 

Other costs in Denmark refer to balancing costs. There is a subsidy for balancing costs in 

Denmark of €3/MWh ($4/MWh), which is assumed to equal the actual balancing costs of a wind 

turbine. Other costs have little effect on the LCOE relative to the Reference Case 

Non-Wind Energy Policy 

In the Danish case, non-wind energy policy refers to corporate taxes and the deduction of interest 

payments from taxable income. Denmark has a lower corporate tax than the Reference Case, so 

it can deduct a large portion of interest payments from taxable income. In addition, it has a high 

debt-to-equity ratio in wind projects. This reduces the LCOE by €1/MWh ($1/MWh) compared 

to the reference case. 

The Danish rules on depreciation are not reflected in the calculations. In Denmark, the value of 

industrial equipment, which includes turbines, may be depreciated annually by a maximum of 

25% of their residual value. This reduces the non-wind energy policy costs in a linear 

depreciation. This reduction has not been calculated. 

Revenues and Wind Energy Policies and Incentives 

The model’s financial gap calculation is used to compare the value of the Danish revenue 

variables to the wind energy policies and incentives variables. The financial gap is first 

calculated without any revenue or any wind energy policies and incentives variables. Next, the 

financial gap is recalculated including only the revenue variables. Lastly, the financial gap is 

recalculated including the wind energy policies and incentives variables. This incremental 

process identifies the relative value of revenue variables to policy incentive variables. 

Figure 2-4 compares the revenue variables to the policy incentive variables, and together, how 

they constitute the Danish LCOE. Of the €61/MWh ($85/MWh), approximately €43/MWh 

($60/MWh) is covered by revenue sources (electricity sales), while €24/MWh ($33/MWh) is 

covered by incentives in the form of the feed-in tariff supplement over the projects lifetime. In 

relative terms, around 2/3 of the Danish LCOE is covered by revenue components, while the 

remaining 1/3 is covered by the feed-in tariff. 

35 
 

          

‐14

0

14

28

42

56

70

83

97

‐10

0

10

20

30

40

50

60

70

LCOE (2008 $/MWh)LCOE (2008 €/MWh)

€43 ($60)

€24 ($33)

‐€6 (‐$8)

€61 ($85)

Denmark LCOE Revenues Wind energy policies FinancialGap

and incentives

Figure 2-4. Danish revenues and wind energy policies and incentives in 200820 

The financial gap in the Danish modeling analysis is approximated at -€6/MWh (-$8/MWh). 

This suggests that on average, wind project developers and investors in Denmark receive 

sufficient cash flow from electricity revenue and wind energy policy incentives to meet the 

financial requirements for developing and investing in wind power projects. 

Summary of Wind Projects in Denmark 

Interest in investing and deploying onshore wind turbines has been revived since the introduction 

of new regulations for remuneration of wind turbines in 2008. Even though interest in onshore 

wind power is increasing, government focus is firmly on introducing offshore wind farms. A 

short term target of 800 MW of offshore wind capacity by the end of 2012 was set in 2008. The 

land based target was set at 175 MW for new onshore capacity and 175 MW for repowered 

capacity. 

The cost of wind power in Denmark is lower than the Reference Case primarily due to lower 

investment costs, but lower financial and operational costs contribute as well. The cost of 

onshore wind power is expected to be lower in the near future due to lower prices for turbines. 

Early indications are that the levelized cost for wind power in 2009 was €59/MWh ($82/MWh) 

20 Data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, wind energy policies 

and incentives, and the financial gap may differ slightly from the country LCOE. 

36 
                               

 

 

 

 

 

compared with €61/MWh ($85/MWh) in 2008. This primarily is due to lower turbine costs, but 

the financial gain of cheaper turbines has been reduced by lower electricity prices. The financial 

gap for turbines erected in 2009 is estimated to be -€5/MWh (-$7/MWh). Despite this slight 

decrease, onshore wind power in Denmark remains an attractive investment under the current 

feed-in tariff. 

The levelized costs for offshore are calculated on the basis of the winning bid price for each 

project. The cost of offshore wind power in Denmark increased by 15% in 2008 compared to 

2007. This most likely was due to increasing turbine costs and bottlenecks in the supply of 

offshore construction vessels, higher cable prices, and increasing costs for steel and 

commodities. Table 2-8 below provides a summary of the cost of wind power in 2007 and 2008. 

Table 2­8. Summary of levelized cost of electricity for Danish wind power in 2007 and 200821

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Levelized cost of energy 

Total revenues and wind energy policies and 

incentives 

Financial gap for developer 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

-

-

-

61 (85) 

67 (93) 

-6 (-8) 

70 (97) 

67 (93) 

3 (4) 

81 (113) 

79 (110) 

2 (3) 

Though prices have fallen for components and raw materials since 2008, along with the 

appearance on the market of more offshore turbines, the cost of offshore wind power in Denmark 

is expected to increase. This is due partially to the availability of increasingly higher subsidies in 

the United Kingdom and Germany, which has increased the opportunity costs of investing in 

Danish offshore projects. Other reasons for increasing prices are the small market for offshore 

wind in Denmark in comparison to the major European offshore markets; the policy of tendering 

single offshore projects with relatively long intervals between tenders, which increases 

transaction costs for bidders; and the low level of competition in the bidding process (only two 

major market participants exist in the Danish offshore sector). The division of risk in the Danish 

concessionary process appears to be an important factor in increasing the cost of offshore wind 

power in Denmark and reducing the attractiveness of the Danish offshore power market for 

investors. 

Another reason for the increased costs of offshore wind power in Denmark is that companies 

may have submitted bids at breakeven prices or very low levels of income to gain experience 

with offshore wind power so they can profit from the experience in more lucrative markets, such 

as the UK. This would make the levelized cost predictions in Table 2-8 lower than they are in 

reality. 

There also are indications that the budgeting of offshore wind farms has been problematic and 

that many have overreached the original budget. If this is the case, then the calculation of the 

levelized costs based on the original bid price would result in a lower levelized cost than in 

reality. 

21 As previously mentioned, data labels are rounded to the nearest whole numbers. Therefore, the sum of the 

revenues, wind energy policies and incentives, and the financial gap may differ slightly from the country LCOE. 

37 
The winning bid price for the 400 MW Anholt offshore wind farm was €141/MWh 

($196/MWh). This represents a doubling of the price the state pays for offshore wind power 

compared to 2007. 

Technical issues such as increasing distances from shore, and sites in deeper water, may also 

influence future investment costs, but these may be offset by technical improvements and 

learning curves. 

It is likely that government-sponsored concessions to produce offshore wind power will make up 

the bulk of offshore investments in the future. The economics of “open door” offshore plants are 

generally not attractive unless they are situated very near the coast and are in very shallow water, 

so called “feet in the water” projects. 

38 
 

References 

Danish Wind Industry Association, 

http://windpower.org/en/knowledge/statistics/the_danish_market.html, September 2010 (Danish 

Wind Industry Association, 2010) 

Danish Energy Agency, Energy Statistics 2007, 2008 (Danish Energy Agency, 2008) 

Danish Energy Agency, Energy Statistics 2008, 2009 (Danish Energy Agency, 2009) 

European Commission, National Renewable Energy Action Plans of the European Member 

States, June 2010 (European Commission 2010), at 

http://ec.europa.eu/energy/renewables/transparency_platform/action_plan_en.htm 

Ministry of Climate and Energy, National handlingsplan for vedvarende energi i Danmark, 2010 

(In English: National Action Plan for RE in Denmark) (Kemin, 2010) 

Nielsen et al, Economy of Wind Turbines, 2010, EUDP (Nielsen et al, 2010) (Original title, 

Vindmøllers Økonomi) 

Saabye, N. Risikopræmie på aktier, 2003, National Bank of Denmark (Saabye, 2003) 

39 
Chapter 3: Germany 

Overview of Wind Industry in Germany 

Capacity, Energy Production, Near-Term Targets 

The development of wind energy in Germany began in the early 1990s. Since then, more than 

23.9 GW of onshore wind energy capacity has been installed. Annual installations have slightly 

decreased since 2002, the year with the highest annual installations at 3.2 GW. Total onshore 

capacity is expected to increase to 30.6 GW by the end of 2012. The wind energy capacity 

projections in 2012 and 2020 are from the National Renewable Energy Action Plans (NREAP) of 

the European Member States (European Commission 2010). 

In 2009, the construction of the first offshore wind farm, Alpha Ventus, was completed. Because 

of this, offshore development can be expected to begin in the near future. The German 

government has announced a goal of approximately 2.5 GW of cumulative offshore wind 

capacity by the end of 2015. 

50 5.0 

Cumulative Offshore (left axis) 45 4.5 

Cumulative Onshore (left axis)
 

Total Annual CapacityAdditions (right axis)
 40 4.0 

Cummulative Capacity (GW) 

Annual Capacity (GW) 

Installed 

Before 2000

200020012002200320042005200620072008

2012

Projection

2020

Projection 

Sources: BMU, Leitszenario 2009 and European Commission 2010 

Figure 3-1. Cumulative and annual wind installations in Germany 

35 

30 

25 

20 

15 

10 

5 

0 

3.5 

3.0 

2.5 

2.0 

1.5 

1.0 

0.5 

0.0 

In 2000, electricity production from wind energy was 1.6% of the gross domestic electricity 

production in Germany. During the past eight years, this share has significantly increased to 

40 
             

 

 

             

 

 

 

6.2%. Taking into account the estimated increase of wind energy production capacities and the 

efforts of the German government to improve efficiency of electricity consumption, this share is 

expected to increase continuously into the future. 

Table 3-1 presents historical and projected cumulative wind energy installed in Germany. 

Table 3­1. Cumulative GW installed in Germany

Installed 

Before Projection Projection 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2012 2020 

Onshore 4.4 6.1 8.8 12.0 14.6 16.6 18.4 20.6 22.2 23.9 30.6 35.8 

Offshore 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.8 10.0 

Source: BMU, Leitszenario 2009 and European Commission 2010
 

Table 3-2 shows historical and projected annual capacity additions.
 

Table 3­2. Annual GW installed in Germany

Installed 

Before Projection Projection 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2012 2020 

Onshore 4.4 1.7 2.7 3.2 2.6 2.0 1.8 2.2 1.7 1.7 1.4 0.3 

Offshore 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 1.7 

Source: BMU, Leitszenario 2009 and European Commission 2010 

Revenue and Policy Incentives 

Wind energy in Germany has been supported by the Renewable Energy Law (EEG) since 2000. 

The law was amended in 2004 and 2008. The last two versions are briefly described below 

following a general description on the EEG mechanism. 

General 

The EEG regulates the support of all renewable energy sources, including onshore and offshore 

wind energy. The produced energy is sold under a fixed feed-in tariff. 

The onshore feed-in tariff consists of two steps: a lower basic tariff and a higher premium tariff. 

Every project will receive the higher tariff for at least five years. The duration of the premium 

tariff is dependent on the quality of the project site. For each different wind turbine type, a 

reference annual energy production (calculated reference for a fixed reference site22) is 

announced. After five years of operation, this reference energy production will be compared to 

the actual production of the turbine at the project site. The duration of the premium tariff is 

extended by two months for each 0.75% that the project site’s energy production is below 150% 

of the reference site’s energy production. The project has to reach an annual energy production 

of at least 60% of the reference production to participate on the EEG. 

22 Note that the German reference site does not refer to the Reference Case used in this report. 

41 
The offshore tariff also consists of two steps. The higher premium tariff will be paid for at least 

12 years. If the offshore wind farm is located at a site with a water depth greater than 20 meters, 

and/or a distance from the coast that is greater than 12 nautical miles, the duration of the 

premium tariff increases. For each meter of water depth greater than 20 m, the duration of the 

premium tariff is extended by 1.7 months. Additionally, the duration of the premium tariff 

extends by one half of one month for each nautical mile of distance from the coast in excess of 

12 nautical miles. 

EEG 2004 

The onshore basic tariff was €55/MWh ($76/MWh), whereas the premium tariff was €87/MWh 

($121/MWh). Both tariffs within EEG 2004 decreased with an annual regression rate of 2%. The 

duration of the premium tariff for new sites was determined according to the mechanism 

mentioned above. For repowering projects, the duration continued for each 0.60% that the actual 

energy production was below 150% of the reference energy production. 

The basic offshore tariff was approximately €62/MWh ($86/MWh), whereas the premium tariff 

was €91/MWh ($127/MWh). The duration of the premium offshore tariff is determined 

according to the general EEG mechanism described above. 

EEG 2009 

The EEG onshore basic tariff was updated in 2009 to €50.2/MWh ($69.8/MWh) and the 

premium tariff changed to €92/MWh ($128/MWh). Both tariffs will decrease annually using a 

regression rate of 1% based on the year of construction of the wind farm. Therefore, a project 

built in 2009 receives a premium tariff of €92/MWh ($128/MWh), whereas a project built in 

2010 will have a premium tariff of €91/MWh ($126/MWh). If the project is a repowering 

project, there is an additional bonus of €5/MWh ($7/MWh). In certain instances, wind turbines, 

which are able to support electricity grids (e.g. low frequency), receive a bonus of €5/MWh 

($7/MWh) as will new projects installed before 2014. The bonus increases to €7/MWh 

($10/MWh) for existing projects, if the wind turbines are optimized until 2010. 

Offshore wind farms benefit from a basic tariff of €35/MWh ($49/MWh). The premium tariff for 

offshore wind farms is €130/MWh ($181/MWh) and is paid for 12 years. If a project is 

constructed before 2016, an additional bonus of €2/MWh ($3/MWh) will be paid. The extension 

of the premium tariff follows the general EEG mechanism. 

Typical Onshore and Offshore Wind Energy Projects in Germany 

Onshore 

The quality of onshore sites for wind energy projects in Germany varies substantially. The good 

quality sites are located in the North and on the Baltic Sea coasts. Even though the site quality 

decreases the further south a project is located, the majority of sites are located in the south of 

Germany. The following describes a typical German wind energy project in 2007. The quality of 

this site is relatively good compared to the average sites exploited in 2007. This site is expected 

to realize roughly 2,260 equivalent full-load hours. 

Project Features 

The average rated power of wind turbines installed in Germany in 2007 and 2008 was about 2 

MW. Approximately 65% of the machines had a rated power of exactly 2 MW. The availability 

42 
of suitable areas for the construction of wind farms in Germany was relatively low in 2007 and 

2008. This resulted in the installation of many small wind farms with a minor number of wind 

turbines installed. The biggest projects installed in these years had a rated power of 30 MW. 

Furthermore, quite a high number of single turbines were installed in these years. A wind farm 

consisting of five turbines was chosen for the model. 

In recent years, wind energy projects at sites in the south of Germany have been developed. 

Because of the lesser quality of these sites in comparison to the German reference site, a project 

site was chosen with a quality that is 90% of the German reference site. 

Investment Costs 

Investment costs depend on the rated power, the rotor diameter of the wind turbine as well as the 

hub height, and the general design concept of the wind turbine (ratio between rated power and 

rotor diameter). The German project turbine has a rated power of 2 MW, a hub height of 100 

meters, and a rotor diameter of 75 meters. In 2007, the total investment for such a machine was 

approximately €1,259/kW ($1,750/kW) including all additional investments like the foundation, 

grid connection, etc.. Due to increasing prices, investment in the same machine increased from 

approximately €1,100/kW ($1,529/kW) to roughly €1,370/kW ($1,904/kW) in 2008. 

Operations and Maintenance Costs 

O&M costs include maintenance by the turbine manufacturer and other third party service 

providers, periodic inspection by external experts, insurances, technical and economic 

management, the cost of energy consumption, land rent, and other costs. In 2007, annual O&M 

costs were €45.71/kW ($63.5/kW) while annual O&M costs of €46.33/kW ($64.4/kW) were 

incurred in 2008. 

Financing Costs 

An equity share of 30% was chosen for the model, and the debt share was 70%. No municipal 

participation was assumed. The return on equity was assumed to be 9.5% and 5.5% for the 

interest rate on debt. The low interest rates resulted from a low revenue risk rating since grid 

access was guaranteed with preferential feed-in, and there are guaranteed and fixed payments 

from the feed-in tariffs. 

Revenue and Policy Incentives 

The revenue is generated from the energy feed-in and the related tariff. The premium tariff for 

projects erected in 2007 was €81.9/MWh ($113.84/MWh) and the basic tariff was €51.8/MWh 

($72/MWh). Based on project site quality, the premium tariff will be applied for 18.3 years. 

Source of Data 

Data is derived from EEG (2004), DEWI Magazine Nos. 32 (2008) and 34 (2009), and the 

scientific report for the abatement of EEG (2008) prepared by Deutsche WindGuard GmbH for 

ZSW. The value of the corporate tax is from Destatis. 

Offshore 

The following information is based on projections from 2008 for future offshore wind farms. 

43 
 

Project Features 

The offshore project is assumed to have a cumulative power of 60 MW from the installed 

capacity of 12 offshore wind turbines. The project is located in the North Sea, approximately 40 

kilometers from the East Frisian Island of Borkum. The water depth at this site is around 30 

meters. The distance from the coast and the water depth require offshore wind turbines, with a 

rated power of approximately 5 MW, to realize an economic benefit. This site has an expected 

3,700 equivalent full-load hours. 

Investment Costs 

Distance and the deep water investment costs for German offshore wind farms are higher in 

comparison to the international average at (€3,230/kW) ($4,490/kW). These costs include wind 

turbines, foundations, a substation, and transmission cables. The grid connection to the onshore 

grid is the responsibility of the grid operator. Therefore, there are no connection costs for the 

connection to the onshore grid in the project investment costs. 

Operations and Maintenance Costs 

Compared to onshore operation and maintenance costs, offshore O&M costs are substantially 

higher. Because of the distance from the coast, there are increased transportation expenses for 

personnel and materials from the mainland to the wind turbines offshore. In addition, O&M 

maintenance costs include external and internal staff, necessary inspections, insurances, and 

costs of economic and technical management as well as the cost of ship traffic observations. 

Annual O&M costs of the German offshore wind energy projects are expected to be €123/(kW) 

($171/kW). 

Financing Costs 

In comparison with onshore projects, investors of offshore projects require higher returns. The 

return on equity (12%) as well as the interest on debt (6.5%) are higher for offshore projects than 

for onshore. The shares of equity (30%) and debt (70%) are constant in comparison with the 

assumed onshore project. In reality, this might be slightly different due to the structure of project 

funding (e.g., project financed versus balance sheet financed projects). 

Revenue and Policy Incentives 

Electricity from offshore wind energy is refunded by EEG feed-in tariffs. For the assumed 

model, the premium tariff is €91/MWh ($127/MWh) and the basic tariff is €61.9/MWh 

($86.0/MWh) according to the EEG 2004. Therefore, the premium tariff will be paid for 14.5 

years based on the project site’s distance from the coast and the water depth. 

Source of Data 

Data is derived from EEG (2004), the scientific report for the abatement of EEG (2008), 

prepared by Deutsche WindGuard GmbH for ZSW. 

Model Input Assumptions 

Tables 3-3 through 3-5 provide the modeling assumptions used in the levelized cost of energy 

analysis that follows. 

44 
               

 

 

 

 

 

 

               

 

 

 

                   

 

 

 

 

 

 

t 

 

 

Table 3­3. Wind energy project features in Germany

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Unit size 

Number of turbines 

Production 

Economic life 

Investment costs 

O&M costs fixed 

O&M costs variable 

Decommission costs 

Other costs 

MW 

N 

full load hours 

years 

€/kW ($/kW) 

€/kW ($/kW) 

€/MWh($/MWh) 

€/kW ($/kW) 

€/MWh ($/MWh) 

2 

5 

2,260 

20 

1,259 (1,750) 

45.71 (63.5) 

-

1.49 (2.07) 

-

2 

5 

2,260 

20 

1,373 (1,908) 

46.33 (64.4) 

-

1.52 (2.11) 

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

5 

12 

3,700 

20 

3,230 (4,490) 

123 (171) 

-

-

-

Source: Deutsche WindGuard 

Table 3­4. Wind energy financing terms in Germany

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Return on debt % 5.5 5.5 N/A 6.5 

Return on equity % 9.5 9.5 N/A 12.0 

Debt share % 70 70 N/A 70 

Equity share % 30 30 N/A 30 

WACC % 5.6 5.6 N/A 6.8 

Loan duration years 13 13 N/A 15 

Corporate tax rate % 29.8 29.8 N/A 29.8 

FX rate $US/€ 1.39 1.39 N/A 1.39 

Source: Deutsch WindGuard, Destatis 

Table 3­5. Wind energy policy and revenue incentives in Germany

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Market price electricity 

Market price certificates 

Average FIT revenue 

FIT policy period 

Upfront tax-based subsidy before tax 

Production-based before tax credits 

Production-based before tax credit 

policy period 

Depreciation period 

Reactive power bonus 

Low voltage ride through bonus 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

Years 

% 

€/MWh ($/MWh) 

Years 

Years 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

-

-

79 (110) 

20

-

-

16

-

-

-

-

78 108 

20 

-

-

16 

-

-

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

-

-

84 (117) 

20 

-

-

16 

-

-

Source: Deutsche WindGuard 

45 
 

 

 

   

         

         

85

Cost Comparison for a German Onshore Project (2008) to the Reference Case: 

Figure 3-2 shows that the LCOE in Germany (€85/MWh) ($118/MWh) is substantially higher 

than in the Reference Case described earlier in this report. The reasons for this variation are 

illustrated below. 

Cost of Wind Energy Generation 

90 125

80

€68 ($95)

€85 ($118)

€9 ($13) €3 ($4)

€5 ($7)

€7 ($10) €1 ($1)

Decreases LCOE FromReference Case LCOE

Increases LCOE FromReferenceCase LCOE

111

LCOE (2008 €/MWh) 75 104

70 97

65 90

60 83

55 76

50 70 ReferenceCase LCOE Project output Total investment

&

decommissioning costs

Financing costs

Annual operations

&

maintenance costs

Other costs

Non‐Wind energy

related policies

Germany LCOE

Country‐Specific InputVariables

Figure 3-2. Wind energy costs in Germany in 200823 

Project Output 

The major reason for the difference of LCOE can be found in the project output. The Reference 

Case capacity is nearly 2,630 full-load hours per year. However, the German base project fullload hours are significantly less at 2,260 per year. 

Investment Costs 

Investment costs for wind energy in 2008 in Germany were roughly €1,373/kW ($1,908/kW), 

which is €76 ($106) less than the Reference Case. In terms of LCOE, this equals a reduction of 

about €3/MWh ($4/MWh). 

Operations and Maintenance Costs 

Operation and maintenance costs of a German wind energy project are higher than in the 

Reference Case by approximately €7/MWh ($10/MWh). Several reasons for the additional costs 

23 Data labels are rounded to the nearest whole numbers. Therefore, the sum of input variables may differ slightly 

from the total Reference Case – Country LCOE differential (due to rounding). 

LCOE (2008 $/MWh)

46 

118
    

 

          

include the commitment of periodic inspections and the small size of German wind farms, which 

leads to increased costs of stocking spare parts. 

Financing Costs 

The difference between the German onshore project and the Reference Case is roughly €5/MWh 

($7/MWh) and occurs because of different financing structures. 

Other Costs 

No other costs are assumed. 

Revenues and Support Mechanisms 

Electricity produced by wind energy will achieve a fixed feed-in tariff according to the EEG. No 

other revenues can be expected for a German wind energy project as long as it is treated under 

either the EEG 2004 or the EEG 2009. Furthermore, no other incentives are intended or expected 

to support German wind energy projects. 

‐14

0

14

28

42

56

70

83

97

111

125

‐10

0

10

20

30

40

50

60

70

80

90

LCOE (2008 $/MWh)LCOE (2008 €/MWh)

€43 ($60)

€79 ($110)

€5 ($7)

€85 ($118)

Germany LCOE Revenues Wind energy policies FinancialGap

and incentives

Figure 3-3. Wind energy revenue and policy incentives in Germany (2008)24 

24 Data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, wind energy policies 

and incentives, and the financial gap may differ slightly from the country LCOE. 

47 
             

 

 

 

 

Financial Gap 

As shown in Figure 3-6, there is a financial gap of €5/MWh ($7/MWh). The main reasons for 

this financial gap are the differences in full-load hours and in the operation and maintenance 

costs. 

Summary 

The chosen German onshore wind farm example consists of five wind turbines with a rated 

power of 2 MW. The full-load hours of the project are assumed to be 2,260. The model 

assumptions led to an estimated LCOE of €85/MWh ($118/MWh). The offered feed-in tariff 

results in a financial gap of approximately €5/MWh ($7/MWh) for the project developer. The 

level of the tariffs is regulated in the EEG. 

Table 3­6. Summary of results for Germany25 

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Levelized cost of energy 

Total revenues and wind 

energy policies and incentives 

Financial gap for developer 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

79 (110) 

79 (110) 

-2 (-3) 

85 (118) 

79 (110) 

5 (7) 

N/A 

N/A 

N/A 

135 (188) 

84 (117) 

46 (64) 

25 As previously noted, data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, 

wind energy policies and incentives, and the financial gap may differ slightly from the country LCOE. 

48 
References 

BMU, Leitszenarion 2009 – Bundesministerium für Umwelt; Naturschutz und Reaktorsicherheit, 

Langfristszenarien und Strategien für den Ausbau erneuerbarer Energien in Deutschland – 

Leitszenario 2009 (2009) 

Destatis: Statistisches Bundesamt; www.destatis.de (last access December 2009) 

Dewi Magazin: - Deutsches Windenergie-Institut, DEWI Magazin No. 32; Wind Energy Use in 

Germany – Status 31.12.2007 (2008) 

Dewi Magazin: - Deutsches Windenergie-Institut, DEWI Magazin No. 34; Wind Energy Use in 

Germany – Status 31.12.2008 (2009) 

Deutsche WindGuard: Deutsche WindGuard GmbH on behalf o Zentrum für Sonnenenergieund Wasserstoff-Forschung Baden-Württemberg (ZSW); Vorbereitung und Begleitung bei der 

Erstellung eines Erfahrungsberichtes gemäß § 20 EEG (2008) 

EEG 2004 - Deutscher Bundestag; Gesetz zur Neuregelung des Rechts der Erneuerbaren 

Energien im Strombereich (2004) 

EEG 2009 - Deutscher Bundestag; Gesetz zur Neuregelung des Rechts der Erneuerbaren 

Energien im Strombereich und zur Änderung damit zusammenhängender Vorschriften (2008) 

European Commission, National Renewable Energy Action Plans of the European Member 

States, June 2010 (European Commission 2010), at 

http://ec.europa.eu/energy/renewables/transparency_platform/action_plan_en.htm 

49 
Chapter 4: Netherlands 

Overview of Wind Industry in the Netherlands 

Capacity, Energy Production, Near-Term Targets 

The installed wind capacity has increased from 447 MW in 2000 to 2,121 MW at the end of 

2008, of which 228 MW is offshore wind capacity. The annual wind energy production has risen 

from 0.8 TWh (2000) to 4.3 TWh (2008). In comparison, the total electricity consumption in the 

Netherlands in 2008 was 119 TWh. The near-term target for onshore wind is 2,000 MW of 

additional installed capacity between 2008 and 2012. This target coincides with the 

approximately 4,000 MW total capacity, installed or under construction. In 2009, a tender for 

950 MW of offshore wind will be launched. Offshore wind has a target of 6000 MW installed 

capacity by 2020. However, to fulfill the obligation for the Netherlands under the Renewable 

Energy Directive of the European Union, just 5178 MW is projected in 2020. 

Figure 4-1 and Tables 4-1 and 4-2 show the onshore and offshore cumulative and annual 

capacity installations, as well as projections of near-term and long term targets/goals by year. 

Note all capacity data is year-end data. The Netherlands does not have repowering targets. 

0 

400 

800 

1,200 

1,600 

2,000 

2,400 

0 

2,000 

4,000 

6,000 

8,000 

10,000 

12,000 

Annual Capacity (MW) 

Cummulative Capacity (MW) 

Cumulative Offshore (left axis) 

Cumulative Onshore (left axis) 

Total Annual CapacityAdditions (right axis) 

Installed 

Before

2000

200020012002200320042005200620072008

2012

Projection

2020

Projection 

Source: Statistics Netherlands, 2010 and Rijksoverheid, 2010 

Figure 4-1. Cumulative and annual wind installations in the Netherlands 

50 
             

 

           

               

 

             

 

 

The annual installed capacity in 2000 was set to equal the year-end cumulative installed capacity 

in 2000. The net annual installed capacity shown in Table 2 is net of decommissioned wind 

energy projects. The net annual installed capacities, in the 2009 – 2012 and 2012 – 2020 periods, 

included in 4-2, represent the average annual installed capacity in these periods. The capacities 

given in the tables below are projections of installed capacities based on the Renewable Energy 

Action Plan of the Dutch government (Rijksoverheid, 2010). 

Table 4­1. Cumulative GW installed in the Netherlands

 Installed 

Before Projection Projection 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2012 2020 

Onshore 0.409 0.447 0.485 0.672 0.905 1.075 1.224 1.453 1.641 1.921 2.727 6.000 

Offshore 0 0 0 0 0 0 0 0.108 0.108 0.228 0.228 5.178 

Source: Statistics Netherlands, 2010 and Rijksoverheid, 2010

Table 4­2. Net annual GW installed in the Netherlands

 Installed 

Before Projection Projection 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2012 2020 

Onshore 0.409 0.038 0.038 0.187 0.233 0.170 0.149 0.229 0.188 0.280 0.202 0.409 

Offshore 0 0 0 0 0 0 0 0.108 0 0.120 0 0.619 

Source: Statistics Netherlands, 2010 and Rijksoverheid, 2010

Revenue and Policy Incentives 

Since 2008, a new feed-in premium scheme, SDE, is in force. Under the SDE scheme, a 

premium is paid on top of the wholesale electricity price to meet the actual electricity production 

costs for wind energy. Additional benefits from soft loan and tax incentives, which are applicable 

for investments in renewable energy technology, are considered in the SDE premium. 

Typical Wind Energy Projects in the Netherlands 

In the following, representative projects will be described for both onshore and offshore wind 

energy in the Netherlands. 

Onshore 

Project Features 

Since 2003, the Netherlands has had a feed-in system that supports wind on the basis of full load 

hours. Until 2006, feed-in was provided for up to 18,000 full load hours per project for a 

maximum of 10 years. Since 2008, the feed-in support aims at projects with at least 2,200 full 

load hours. The average full load hours are about 2,000 hours/year, with a common range 

between 1,600 and 2,800 hours/year. 

The Dutch onshore project shows the reference project used in calculations of the feed-in 

support.26 The project sets the cost level at which the majority of the projects initiatives are 

financially viable. A typical size is a small wind farm of 15 MW. Most of the wind projects use a 

2-3 MW turbine (90 meter rotor diameter), with hub heights of 60 to 80 meters. In some regions, 

26 Note that the “reference project” does not refer to the “Reference Case” used in this analysis. 

51 
a height limitation is imposed. In those regions, a 450-800 kW turbine, with a hub height of 40­

60 meters, is common. 

Investment Costs 

Typical project investment costs range from €1,000/kW ($1,390/kW) to more than €1,600/kW 

($2,224/kW), and, generally speaking, high investment costs correspond to high full load hours. 

Operations and Maintenance Costs 

The operational costs include a production dependent component of €9-12/MWh ($13­

$17/MWh), typically with service contracts for the first five years of operation, and a capacity 

dependent component of €25/kW ($35/kW), which includes land rent and grid connection costs. 

The capacity dependent component can vary significantly between projects. The real operational 

costs are assumed to increase with 2% per annum. 

Financing Costs 

The model uses project financing with 80% annuity based debt, reflecting investments of project 

developers. An equity rate of 15% is assumed fair by the government (as the subsidy provider), 

with a debt rate of 6%. Utility companies mostly finance on their balance sheets. The corporate 

tax rate is 25.5%. 

Revenue and Policy Incentives 

The main revenues are electricity sales through long term contracts, primarily on the forward 

market, and feed-in premiums cover the financial gap. Generic additional incentives are given 

through soft loans and an energy investment allowance. The energy investment allowance is 

assumed to lower the equity share. Structures using this tax benefit vary, ranging from 

developers with lack of taxable income to those who use the funds for their benefit against a 42% 

income tax. 

Source of Data 

The data used for this task is the published data of the reference projects that are used in the 

calculations of the Dutch feed-in premiums (Lensink et al., 2009, Cleijne et al., 2010). 

Offshore 

Project Features 

Offshore wind projects in the Netherlands can receive a building permit to erect a wind farm in a 

maximum area of 50 km2

. Typical offshore projects are, therefore, 100-300 MW in capacity. The 

net production delivered to the grid equals 3,300-4,000 full load hours. In 2008, the Prinses 

Amalia wind farm was completed. The presented data does not necessarily reflect the cost 

structure of that specific wind farm. 

Investment Costs 

The investment costs are in the range of €2,500-3,500/kW ($3475-4865/kW). The project that 

was completed in 2008 uses a rather small V90 with 2 MW due to limiting conditions in the 

permit that had been granted several years before. 

52 
               

 

 

 

 

 

               

 

 

 

 

Operations and Maintenance Costs 

Operational costs show a large uncertainty, due to lack of hands-on experience by the operator. 

The costs are estimated at €90/kW ($125/kW) per annum. 

Financing Costs 

The model uses a project based financing structure, with 50% debt. The Prinses Amalia wind 

farm has been financed on the project basis. The assumed WACC approaches the cost of capital 

of balance financing, which has been used for another existing offshore wind farm , owned by 

Nuon/Shell and named OWEZ. 

Revenue and Policy Incentives 

The existing wind farms receive subsidies under the old MEP scheme: a fixed feed-in premium 

of €97 €/MWh (€135/MWh). Soft loans and an incentive subsidies apply. 

Source of Data 

The data is derived from press notices and other publicly available information, where the 

information gaps are covered by modeling exercises based on non-disclosed information. 

Model Input Assumptions 

Tabular presentations show input assumptions, onshore and offshore, for each year. Costs for 

2007 projects are in €2008. The market price of electricity in Table 4-5 includes transaction and 

balancing costs as well as discounts for long term contracts. 

Table 4­3. Wind energy project features in the Netherlands

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Unit size MW 1 15 120 N/A 

Number of turbines N 1 5 60 N/A 

Production (full load hours) 2,000 2,200 3,350 N/A 

Economic life (years) 20 20 15 N/A 

Investment costs €/kW ($/kW) 1,120 (1,557) 1,325 (1,842) 3315 (4,608) N/A 

O&M costs fixed €/kW ($/kW) 40 (56) 24 (33) 92 (128) N/A 

O&M costs variable €/MWh ($/MWh) N/A 11 (15) N/A N/A 

Decommission costs €/kW ($/kW) N/A N/A N/A N/A 

Other costs €/MWh ($/MWh) N/A N/A N/A N/A 

Table 4­4. Wind energy financing terms in the Netherlands

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Return on debt 

Return on equity 

Debt share 

Equity share 

WACC

Loan duration 

Corporate tax rate 

FX rate 

% 

% 

% 

% 

% 

(years) 

% 

($US/€) 

5 

15 

80 

20 

6.0 

10 

25.5 

1.39 

5 

15 

80 

20 

6.0 

15 

25.5 

1.39 

5 

12

50

50

7.9

10

25.5

1.39

N/A 

 N/A 

 N/A 

 N/A 

 N/A 

 N/A 

 N/A 

 N/A 

53 
                   

 

 

 

 

 

 

 

 

 

 

 

 

Table 4­5. Wind energy policy and revenue incentives in the Netherlands

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Market price electricity 

Market price certificates 

FIT revenue 

FIT policy period 

Upfront tax-based 

 subsidy before tax 

Production-based before

 tax credits 

Production-based before

 tax credit policy period 

Depreciation period 

Reactive power bonus 

Low voltage ride through 

 Bonus 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

(years) 

% 

€/MWh ($/MWh) 

(years)

(years) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

58 (81) 

N/A

6.63 (9.22) 

10

37 

N/A 

N/A 

10

N/A

N/A

56 (78) 

N/A 

28 (39) 

15 

20 

N/A 

N/A 

15 

N/A 

N/A 

59 (82) 

N/A 

97 (.135) 

10 

44 

N/A 

N/A 

10 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

Unique Aspects of Wind Projects in Netherlands 

Wind projects in the Netherlands have a long lead time, mainly due to the difficulties in 

obtaining the necessary permits. 

54 
  

 

 

   

         

         

95 132

Comparison of Wind Energy Costs in the Netherlands to the Reference Case 

Cost Comparison 

100 139

€68 ($95)

€94 ($131)

€11 ($15)

€6 ($8)

€12 ($17)

€10 ($14) €2 ($3)

Decreases LCOE FromReference Case LCOE

Increases LCOE FromReferenceCase LCOE

90 125

LCOE (2008 €/MWh) 85 118

80 111

75 104

70

65 90

60 83 Reference Case LCOE Project output Total investment

&

decommissioning costs

Financing costs

Annual operations

&

maintenance costs

Other costs

Non‐Wind energy

related policies

Netherlands LCOE

Country‐Specific InputVariables

Figure 4-2. Graphical representation between the Netherlands and Reference Case27 

Project Output 

Wind turbines in the Netherlands have a load factor of about 25% (2,200 full load hours), which 

is lower than the 30% in the Reference Case. As the feed-in subsidy is capped to 2,200 full load 

hours (or even less, taking the specifics of the SDE regulation into account), there is limited 

incentive to produce more than 2,200 full hours. The more important factor remains the wind 

regime. 

Cost of Wind Energy Generation 

Investment Costs 

The total investment costs might be related to the previous issue. There is limited incentive to 

produce more than 2,200 full load hours. It cannot be excluded that turbines are of slightly 

different designs and thus, slightly less expensive. For example, using the same generator but 

smaller rotor blades will reduce the investment costs and increase the number of full load hours. LCOE (2008 $/MWh)

27 Data labels are rounded to the nearest whole numbers. Therefore, the sum of input variables may differ slightly 

from the total Reference Case – Country LCOE differential (due to rounding). 

55 

97
 

          

0

Operations and Maintenance Costs 

The high operational costs are, in part, due to the high cost of land rent, which is about €10/kW 

($15/kW) annually. 

Financing Costs and Other Costs 

Compared to the Reference Case, wind energy in the Netherlands also benefits from the 

relatively low corporate tax rate of 25.5%. Decommissioning costs are not taken into account. 

Revenues and Support Mechanisms 

Wind producers in the Netherlands can benefit from three incentive schemes. The main support 

comes from a feed-in premium. For projects requesting feed-in before 2007, the MEP support 

gives a fixed premium for 10 years. From 2008 forward, the SDE support gives a variable 

premium for 15 years. In addition to the feed-in, soft loans at a 1% discount and an investment 

subsidy (EIA) as a tax deduction for 44% of the investment costs to a maximum of €600/kW 

($834/kW) for onshore projects are available. 

100 139

20

€64 ($89)

€32 ($44)

‐€3 (‐$4)

€94 ($131)

28

10 14

90

80

70

60

50

40

125

111

97

83

70

56

LCOE (2008 €/MWh)LCOE (2008 $/MWh)

30

‐14

Netherlands LCOE Revenues Wind energy policies FinancialGap

and incentives

‐10

Figure 4-3. Wind energy revenue and policy incentives in the Netherlands28 

28 Data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, wind energy policies 

and incentives, and the financial gap may differ slightly from the country LCOE. 

56 

0

42
                

 

 

 

   

 

 

Financial Gap 

The financial gap in the Netherlands for projects that started in 2007 (see Table 4-6) was 

negative, amounting to about -€36/MWh (-$50/MWh). This was caused by a design flaw in the 

previous MEP feed-in scheme. The subsidy was based on expectations of low electricity prices 

(€2 to €3 /MWh) ($3 to $/MWh). As the electricity prices rose to €6-€8 /MWh ($8-11/MWh), 

wind projects became quite lucrative, at least as long as the electricity prices remained high. For 

projects that started in 2008 on the successor SDE feed-in scheme, the flaw was removed. The 

financial gap is slightly negative at -€3/MWh (-$4/MWh). Note that the range of production 

costs between the various projects is far greater than -€3 or more euros. So the negative value of 

-€3/MWh ($4/MWh) is not significantly below zero. 

Wind offshore had a positive financial gap remaining of €5/MWh ($7/MWh). Although this is 

not based on first-hand financial information, it is clear that the Prinses Amalia wind farm did 

encounter difficulties in reaching a financial close. 

Summary 

The Netherlands has ambitious targets for onshore and offshore wind energy, both for the near 

future and for 2020. The current SDE feed-in scheme is the most important tool in realizing this. 

From the analysis in section 3, it follows that the financial gap in the case of the Netherlands is 

not significant. The subsidized electricity production is limited to 2,200 full load hours. Although 

this number is in line with the Dutch wind regime, there is limited incentive to produce more 

than 2,200 hours. The lower investment costs might be a result of this. O&M costs are relatively 

high due to the land cost component. 

Table 4­6. Summary of results for the Netherlands29

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Levelized cost of energy 

Total revenue and wind energy policies and 

incentives 

Financial gap for developer 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

91 (126) 

127 (177) 

-36 (-50) 

94 (131) 

96 (133) 

-3 (-4) 

166 (231) 

161(224) 

5 (7) 

N/A 

N/A 

N/A 

29 As previously noted, data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, 

wind energy policies and incentives, and the financial gap may differ slightly from the country LCOE. 

57 
References 

Cleijne, J.W., S.M. Lensink and C.J. Faasen (2010): SDE Wind op land met vollasturen en 

differentiatie [SDE wind onshore with full load hours and differentation], ECN-E--10-001, 

Petten, January 2010. 

Lensink, S.M., J.W. Cleijne, M. Mozaffarian, A.E. Pfeiffer, S. L. Luxembourg and G.J. Stienstra 

(2009): Eindadvies basisbedragen 2010 [Final advice SDE premium base rates 2010], 

ECN/KEMA, ECN-E--09-058, Petten, November 2009. 

Rijksoverheid (2010): Nationaal actieplan voor energie uit hernieuwbare bronnen, Richtlijn 

2009/28/EG [National Renewable Energy Action Plan, Directive 2009/28/EG], Den Haag, June 

2010. 

Statistics Netherlands (2010): online databank http://statline.cbs.nl, Voorburg/Heerlen August 

2010 

58 
Chapter 5: Spain 

Overview of Wind Industry in Spain 

The following chapter describes the evolution of wind energy in Spain as well as the foreseen 

2020 and 2030 targets, based on certain EU objectives and to reduce CO2 emissions. The present 

regulatory framework is also presented, even if there are now negotiations to review some of its 

key elements to reduce the impact of the cost of the premiums in the retail tariffs. 

Additionally the Levelized Cost of Energy (LCOE) for a typical wind farm in the Spanish market 

in 2008 is also explained and the assumptions are compared with the cost of wind energy in other 

countries. 

Capacity, Energy Production, Near-Term Targets 

At the end of 2009, wind energy accounts for the third largest power generation source of the 

Spanish power system, reaching 19,149 MW at year-end. Wind energy development started in 

Spain in the mid nineties, and since 2001, the average of new wind power capacity has been of 

about 1,800 MW per year. The strong growth in 2004 and 2007 can be explained by the 

regulatory changes that were introduced (Royal Decree 436/2004 and Royal Decree 661/2007) in 

those two years, which led to new projects being initiated to take advantage of the existing 

regulation. 

Wind energy production represented about 14% of the total Spanish electricity demand in 2009. 

Figure 5-1 provides historical cumulative and annual wind energy installations in Spain through 

the year 2008, which is the focus of the cross country comparisons. The wind energy capacity 

projections in 2012 and 2020 are from the National Renewable Energy Action Plans (NREAP) of 

the European Member States (European Commission 2010). The projection in 2020 is addressed 

to accomplish the EU objective of achieving 20% of the demand of energy with renewable 

energies. 

59 
40 4.0 

35 3.5 

Cummulative Capacity (GW) 

30 

25 

20 

15 

10 

5 

0 

Cumulative Offshore (left axis) 

Cumulative Onshore (left axis) 

Total Annual CapacityAdditions (right axis) 

3.0 

2.5 

2.0 

1.5 

1.0 

0.5 

0.0 

Annual Capacity (GW) 

Installed 

Before

2000

200020012002200320042005200620072008

2012 

Projection

2020 

Projection 

Source: Spanish Wind Energy Association (AEE) and European Commission 2010 

Figure 5-1. Cumulative and annual wind installations in Spain 

Table 5-1 presents historical and projected cumulative wind energy installed in Spain and Table 

5-2 presents annual wind installations. It is important to indicate that in 2009, the government 

decided to establish a quota to limit the MWs to be installed every year between 2010 and 2012. 

It has also been announced that future legislation will incorporate a similar scheme, which has as 

its main goal to reduce the weight of the premiums in the retail tariffs (for all renewable energy 

and cogeneration the total amount was 6.000 MW, 25% of the total electricity turnover, 

especially costly in a situation of economic crisis). 

The main obstacle for offshore wind in Spain is the lack of a continental platform, so the depth 

of sea waters is 50m near the coast. Therefore, offshore wind requires important and expensive 

foundations, which will limit the feasibility of these projects. Furthermore, the Common 

Connection Points have a limited access capacity because there are some bottlenecks from 

electricity generated by the Combined Cycles installed close to the regasification hubs. 

60 
             

 

              

 

 

 

     

Table 5­1. Cumulative GW installed in Spain

Installed 

Before Projection Projection 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2012 2020 

Onshore 1.6 2.2 3.4 4.9 6.2 8.5 10.0 11.6 15.1 16.7 23 35 

Offshore 0 0 0 0 0 0 0 0 0 0 0 3 

Source: Spanish Wind Energy Association (AEE) and European Commission 2010 

Table 5-2 shows historical and projected annual capacity additions in Spain. 

Table 5­2. Annual GW installed in Spain

Installed 

Before Projection Projection 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2012 2020 

Onshore 1.6 0.6 1.2 1.5 1.3 2.3 1.5 1.6 3.5 1.6 1.5 1.4 

Offshore 0 0 0 0 0 0 0 0 0 0 0 0.5 

Source: Spanish Wind Energy Association (AEE) and European Commission 2010 

Revenue and Policy Incentives 

To receive the benefits foreseen in the law, the wind projects have to be typified as Special 

Regime (similar to the American Qualifying facilities) because they have priority of access to the 

grid (the electricity surplus has to be purchased by the retailers) and the price is regulated. As 

stated in the Royal Decree 661/2007, there are two pay schemes for wind power: the regulated 

tariff scheme and the market mechanism. 

	 The regulated tariff scheme is a mandated feed-in price for wind generation along the period 

selected by the wind farms owner (values in Figure 5-2). 

2007 2008 2009 2010

Feed‐in tariff (regulated tariff) 73,228 75,681 78,183 77,471

80

79

78

77

76

75

74

73

72

71

70

€/MWh

Source: Spanish Wind Energy Association (AEE) 

Figure 5-2. Evolution of the regulated tariff 

61 
	 The market mechanism, whereby the final price is the combination of the wholesale electrical 

market price, according to the hourly marginal price plus a production incentive, is also 

called premium. So the tariff received by the wind producer will depend on the pool price, 

with a floor if that price is very low and a roof if the price is over a minimum. Figure 5-3 

presents the reference values of the regulated tariff, floor, and roof. 

39,35

64,43

36,96

34,80

21,51

40,04

0

10

20

30

40

50

60

70

80

90

100

2007 2008 2009

€/MWh

Premium

Market price

74,14 €/MWh

85,94 €/MWh

77 €/MWh

Source: Spanish Wind Energy Association (AEE) 

Figure 5-3. Final retribution in the market option (market price plus premium) 

Wind producers present a production program for day-ahead markets, and therefore, they use 

predictions to reduce the deviations between that program and the real production. Furthermore, 

the projects are grouped to reduce the errors thanks to the compensation between wind farms 

settled in different basins. This system allows an optimization of the use of ancillary systems and 

balancing, and the cost is partially paid by the wind producers (around €1.5/MWh ($2.05/MWh) 

in 2008). 

The RD 661/2007 updated the aforementioned values based on the Consumer Price Index, with a 

correction factor of 25 basis points, up to December 31, 2012, and 50 basis points thereafter. 

Figure 5-3 shows the varying feed-in tariff rates since RD 661/2007 came into force. In 2007, 

RD 661/2007 set a feed-in tariff to be renewed in line with the Consumer Price Index, with a 

correction factor of 25 basis points, up to December 31, 2012, and 50 basis points thereafter. In 

2010, the update was negative and the values are lower than the previous year because the CPI 

was near to zero. 

62 
According to the Red Eléctrica de España (REE), the national Transmission System Operator 

(TSO), 9% of capacity was operated through the feed-in tariff option; therefore, it is not affected 

by the variation of the wholesale electrical market price (Figure 5-4). 

Source: Spanish TSO (REE) 

Figure 5-4. Wind capacity on the wholesale market, 2008 

As the greatest part of the wind generation is sold directly on the wholesale market, 

remunerations depend largely on that pool price, which is influenced by the natural gas prices, 

the hydro conditions, and the CO2 prices in the international markets. In this sense, in 2008, the 

average daily pool price was €64.43/MWh ($89.56/MWh), the highest registered to date, 64% 

higher than the 2007 price of €39.35/MWh ($54.70/MWh). 

Wind power purchase prices on the market are illustrated in Figure 5-3, and the wholesale 

electricity prices presented in Figure 5-5. As mentioned earlier, in the case of RD 661/2007, that 

price is the sum of the price on the daily wholesale electricity market plus the premium, within 

the band of a floor and cap. 

63 
                 

28,96 27,94

53,68 50,53

39,35

64,43

36,96

‐22,6%

‐3,5%

92,1%

‐5,9%

‐22,1%

63,7%

‐42,6%

‐100,0%

‐80,0%

‐60,0%

‐40,0%

‐20,0%

0,0%

20,0%

40,0%

60,0%

80,0%

100,0%

‐100

‐80

‐60

‐40

‐20

0

20

40

60

80

100

2.003 2.004 2.005 2.006 2.007 2.008 2.009

Average market price (€/MWh) Variation rate of average market price (%)

€/MWh

Sources: OMEL and Spanish Wind Energy Association (AEE) 

Figure 5-5. Year average of the daily electricity pool price and variation rate, 2003 – 2009 

Typical Wind Energy Project in Spain in 2008 

The following section describes Spanish wind energy project characteristics in 2008, which will 

be used to compare the different models of wind energy development among participating 

countries. 

Onshore 

Project Features 

To have access to the Special Regime system, the Spanish onshore wind farm size should not 

exceed 50 MW. The average size of installed wind parks is around 25 MW and for the 

calculation, the wind farm is assumed to be 30 MW of installed capacity for both 2007 and 2008. 

The nominal operational hours vary from 1,700 to 2,350 hours per year at nominal power (the 

national average for 2008 was 2,085 hours) and the reference value for the project was 2,200 

hours for 2007 and 2,150 hours for 2008. 

In all the financial models used in Spain, the project life cycle is 20 years, even if there is not 

experience of wind farms within this operational span. The value finally selected is of 20 years 

for both 2007 and 2008. 

The average size of the wind turbines installed in 2008 was 1,985 kW; this represents a slight 

increase when compared with the 1,621 kW of 2007. In the model, we will consider a 2,000 kW 

wind turbine, which means 15 wind turbines of 2 MW for the wind farm. 

64 
Source: Spanish Wind Energy Association (AEE) 

Figure 5-6. Size breakdown of wind turbines installed over 2008 

Investment Costs 

The increase of the total investment in the last years has been mainly due to the installation of 

bigger wind turbine generator systems (WTGS), Class III and IV, the connection to high voltage, 

and various taxes not initially foreseen. 

Nevertheless, in the last years, the cost of turbines has been reduced due to the decrease of raw 

material prices, and the decrease in turbine demand by the financial crisis and regulatory 

changes. 

Of the total investment in a wind farm, the cost of the turbine is about 70-73% of the total. This 

cost is closely linked to the price of raw materials and to the complexity of the required 

technology conditioned to the current grid codes. 

For projects installed in 2007, the investment cost is estimated at €1,233/kW ($1,714/kW) and 

€1,250/kW ($1,738/kW) in 2008. 

Operations and Maintenance Costs 

The operations and maintenance costs also rose by the curtailments, the increase of electric selfconsumption tariffs, and the greater technical complexity of the installations. 

The operation and maintenance costs are estimated to €19.10/MWh ($26.55/MWh) in 2007 and 

€19.63/MWh ($27.29/MWh) in 2008 (100% variable costs). These costs are linked to several 

factors including: variation of the wage level, availability of substitute components and of the 

required qualified personnel, and mechanical devices. 

The nominal hours will be reduced since the best sites have been used in spite of the increase of 

the WTG ́s size. 

65 
Financing Costs 

Wind energy projects development in Spain have been historically financed through project 

finance schemes due to the financial capacity of banks operating in Spain as well as the stable 

legal framework. Nevertheless, the situation has changed in the last two years by the lack of 

liquidity of the financing system and some collateral guarantees are also requested. 

The financing costs are established, for year 2007 to 10% of return on equity and 7% of return on 

debt. The equity share is 20% and debt share 80% for 2007 and 2008. For the year 2008, the 

values are 10% for return on equity and 7% for the return on debt. 

Revenue and Policy Incentives 

Revenues from the sale of energy to the market was €39.4/MWh ($54.8/MWh) in 2007 and 

€64.4/MWh ($89.5/MWh) in 2008. These revenues are in addition to the Feed-in Tariff premium 

evaluated at €34.8/MWh ($48.3/MWh) in 2007 and €21.5/MWh ($29.9/MWh) in 2008. The 

Feed-in Tariff policy period is fixed at 20 years for both cases. 

Source of Data 

The data we presented here came from a study realized by the Spanish Wind Energy Association 

(AEE) and Intermoney. 

Offshore 

Project Features 

The Spanish offshore has been divided into 62 areas in which the development of wind power is 

regulated. These areas will be opened to tender. Apart from some experimental initiatives, the 

projected wind farm sizes are around 1000 MW. 

Investment Costs 

No offshore data. 

Operations and Maintenance Costs 

No offshore data. 

Financing Costs 

No offshore data. 

Revenue and Policy Incentives 

No offshore data. 

Source of Data 

No offshore data. 

66 
               

 

 

 

 

 

               

 

 

 

                   

 

 

 

 

 

Model Input Assumptions 

Tables 5-2 through 5-5 provide the modeling assumptions used in the levelized cost of energy 

analysis that follows. All cost assumptions are representative of wind projects in 2007 and 2008, 

and are expressed in 2008 Euros. 

Table 5­3. Wind energy project features in Spain

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Unit size MW 30 30 N/A N/A 

Number of turbines N 15 15 N/A N/A 

Production full load hours 2,200 2,150 N/A N/A 

Economic life years 20 20 N/A N/A 

Investment costs €/kW ($/kW) 1,233 (1,714) 1,250 (1,738) N/A N/A 

O&M costs fixed €/kW ($/kW) 0 0 N/A N/A 

O&M costs variable €/MWh ($/MWh) 19.1(26.6) 19.6(27.2) N/A N/A 

Decommission costs €/MWh ($/MWh) 0 0 N/A N/A 

Table 5­4. Wind energy financing terms in Spain

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Return on equity % 9 10 N/A N/A 

Return on debt % 6 7 N/A N/A 

Equity share % 20 20 N/A N/A 

Debt share % 80 80 N/A N/A 

Loan duration years 15 15 N/A N/A 

Corporate tax rate % 30 30 N/A N/A 

FX rate $US/€ 1.39 1.39 N/A N/A 

Table 5­5. Wind energy policy and revenue incentives in Spain

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Market price electricity 

FIT revenue 

€/MWh 

($/MWh) 

€/MWh 

($/MWh) 

53 (74) 

34 (47) 

54 (75) 

35 (49) 

N/A 

N/A 

N/A 

N/A 

FIT policy period Years 20 20 N/A N/A 

Upfront tax-based subsidy before tax % 0 0 N/A N/A 

Production-based before tax credits 

Production-based before tax credit 

 policy period 

€/MWh 

($/MWh) 

Years 

0 

-

0 

-

N/A 

N/A 

N/A 

N/A 

Depreciation period Years 20 20 N/A N/A 

Reactive power bonus 

Low voltage ride through bonus 

Market Certificates 

€/MWh 

($/MWh) 

€/MWh 

($/MWh) 

€/MWh 

($/MWh) 

3.6 (5.1) 

0 

-

3.7 (5.2) 

0 

-

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

67 
 

 

   

         

         

65

85

€68 ($95)

€83 ($115)

€10 ($14) €1 ($1)

€6 ($8)

€1 ($1)

Decreases LCOE FromReference Case LCOE

Increases LCOE FromReferenceCase LCOE

Cost of Wind Energy Generation 

Cost Comparison 

The 2008 LCOE in Spain is compared to the Reference Case in Figure 5-7, showing the 

differences between the two. The Spain LCOE is €15/MWh ($21/MWh) higher than the 

Reference Case LCOE. 

90 125

75

€18 ($25)

104

LCOE (2008 €/MWh) 80 111

LCOE (2008 $/MWh)

70

60 83 Reference Case LCOE Project output Total investment

&

decommissioning costs

Financing costs

Annual operations

&

maintenance costs

Other costs

Non‐Wind energy

related policies

Spain LCOE

Country‐Specific InputVariables

Figure 5-7. Wind energy costs in Spain and the Reference Case in 200830 

Project Output 

A wind energy project in Spain has less capacity factor on average than the Reference Case. Due 

to the wind conditions, lower full load hours in Spain increase the Spain LCOE to the Reference 

Case LCOE by €18/MWh ($25/MWh). An average of 2,150 full load hours is expected in the 

Spanish case compared with 2,628 hours for the Reference Case. 

The full load hours are the most important variable regarding the differences between the Spain 

LCOE and the Reference Case LCOE. In addition to the wind conditions, the operation and 

maintenance costs also are over the Reference Case, and the land rents and the returns requested 

by regions and municipalities also are included. 

The third element explaining the higher LCOE is the financing costs, which increase the WACC 

of the projects and finally the ROI requested to each specific investment. 

30 Data labels are rounded to the nearest whole numbers. Therefore, the sum of input variables may differ slightly 

from the total Reference Case – Country LCOE differential (due to rounding). 

68 

90

97

118
Investment Costs 

The total investment cost in Spain is about €1,250/kW ($1,738/kW) - lower than the Reference 

Case by about €200/kW ($278/kW). Due to the lower investment cost in Spain, the LCOE is 

€10/MWh ($14/MWh) lower. 

Decommissioning costs, which include the dismantling of wind energy generation equipment 

when the economic life of the wind farm is finalized, are about 3% of the total investment cost. 

Financing Costs 

Regarding the financial conditions, in the Spanish case, the value of return on equity and return 

on debt are higher than the same values of the Reference Case. 

Operations and Maintenance Costs 

In Spain, the operation and maintenance costs are higher than the Reference Case. Total 

operations and maintenance costs in Spain include all kinds of variable costs including taxes, 

rents, and administrative expenses. In the next years, the operation and maintenance costs will 

also rise by the curtailments, the increase of electric self-consumption tariffs, and the greater 

technical complexity of the installations. 

On average, the operation and maintenance costs in Spain are about €19.6/MWh ($27.2/MWh), 

almost €7/MWh ($10/MWh) higher than the Reference Case. 

Revenues and Wind Energy Policies and Incentives 

As mentioned earlier, in Spain there are two pay schemes: a feed-in tariff scheme (a fixed price 

for the wind generation) and a market scheme (the market price plus a premium for the wind 

production). In 2008, almost 91% of the wind production was selling in the market option, 

because it allows developers to obtain higher revenues. 

Figure 5-8 compares the revenue variables (electricity price) to the wind energy policies and 

incentives variables (premium in the market scheme in Spain). 

69 
             

 

 

          

90

€49 ($68)

€37 ($51)

‐€3 (‐$4)

€83 ($115)

125

LCOE (2008 €/MWh)

80

70

60

50

40

111

97

83

70

56

30 42

20 28

10 14

LCOE (2008 $/MWh)

0 0

‐10 ‐14

Spain LCOE Revenues Wind energy policies FinancialGap

and incentives

Figure 5-8. Revenues and wind energy policies and incentives in 200831 

Financial Gap 

The financial gap in the Spanish modeling analysis is approximated at -€3(-$4). This suggests 

that on average, a wind project developer in Spain receives sufficient cash flow from revenue 

and wind energy policies and incentives to meet the financial requirements to develop the 

project. 

Summary of Wind Projects in Spain 

Table 5­6. Summary of results for Spain32

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Levelized cost of energy €/MWh 

($/MWh) 76(106) 83(115) N/A N/A 

Total revenues and wind 

energy polices and incentives 

€/MWh 

($/MWh) 87(121) 86(120) N/A N/A 

Financial gap for developer €/MWh 

($/MWh) -11(15) -3(-4) N/A N/A 

31 Data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, wind energy policies 

and incentives, and the financial gap may differ slightly from the country LCOE. 

32 As previously mentioned, data labels are rounded to the nearest whole numbers. Therefore, the sum of the 

revenues, wind energy policies and incentives, and the financial gap may differ slightly from the country LCOE. 

70 
 

References 

AEE, Spanish Wind Energy Association (2009). “Eólica 09. Todos los datos, análisis y 

estadísticas del sector eólico (Julio 2009)”, at 

http://www.aeeolica.es/userfiles/file/ANUARIO%20COMPLETO%5B1%5D.pdf 

AEE, Spanish Wind Energy Association (2008). “Eólica 08. Todos los datos, análisis y 

estadísticas del sector eólico (Junio 2008)”, at http://www.aeeolica.es/userfiles/file/aeepublica/AEE_anuario_ingles08.pdf 

AEE – Intermoney (2006) “Estudio de costes del sector eólico. Realizado por Intermoney para 

AEE (2006)”, at http://www.aeeolica.es/userfiles/file/aee-publica/060612-Gen-EolicaEspPRAL.pdf 

Comisión Nacional de la Energía (CNE). www.cne.es 

European Commission, National Renewable Energy Action Plans of the European Member 

States, June 2010 (European Commission 2010), at 

http://ec.europa.eu/energy/renewables/transparency_platform/action_plan_en.htm 

Red Eléctrica de España (REE), Spanish TSO. www.ree.es 

Royal Decree 661/2007. http://www.cne.es/cne/doc/legislacion/RD_661-2007-RE.pdf 

Royal Decree 436/2004. http://www.cne.es/cne/doc/legislacion/(36)RD436_2004.pdf 

Spanish Market Operator (OMEL). www.omel.es 

71 
 

Chapter 6: Sweden 

Overview of Wind Industry in Sweden 

The following chapter describes onshore and offshore wind energy project and cost 

characteristics in Sweden, and the assumptions used in modeling the levelized cost of energy 

(LCOE) for onshore wind technologies in 2008. 

Capacity, Energy Production, Near-Term Targets 

Onshore wind energy capacity in Sweden expanded from approximately 474 MW of cumulative 

installations in 2004 to 937 MW by year-end 2008 (Figure 6-1). A 110 MW offshore wind farm 

in Southern Sweden was installed in 2007 and “near shore” lake-based projects have also been 

developed. The wind energy capacity projections in 2012 and 2020 are from the National 

Renewable Energy Action Plans (NREAP) of the European Member States (European 

Commission 2010). 

5,000 

Cumulative Offshore (left axis) 4,500 Cumulative Onshore (left axis)

Annual Capacity Additions (right axis)
 

4,000 

Cummulative Capacity (MW) 3,500 

3,000 

2,500 

2,000 

1,500 

1,000 

500 

0 

350 

300 

250 

200 

150 

100 

50 

0 

Annual Capacity (MW) 

Installed

Before

2000

200020012002200320042005200620072008

2012

Projection

2020

Projection 

Source: Vinkraft Statistik 2009, Vindkraft Statistik 2007, and European Commission 2010 

Figure 6-1. Cumulative and annual wind installations in Sweden 

72 

400 

450 

500 
             

 

             

 

 

Table 6-1 presents historical and projected cumulative wind energy installed in the U.S. 

Table 6­1. Cumulative MW installed in Sweden

Installed 

Before Projection Projection 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2012 2020 

Onshore 220 220 272 322 381 429 470 560 698 951 2,065 4,365 

Offshore 10 20 23 23 23 23 23 23 133 133 150 182 

Source: Vinkraft Statistik 2009, Vindkraft Statistik 2007, and European Commission 2010 

Table 6-2 shows historical and projected annual capacity additions. 

Table 6­2. Annual MW installed in Sweden

Installed 

Before Projection Projection 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2012 2020 

Onshore - 0.5 51 50 59 48 41 90 138 253 278 288 

Offshore - 10 2.5 0 0 0 0 0 110 0 4 4 

Source: Vinkraft Statistik 2009, Vindkraft Statistik 2007, and European Commission 2010 

Revenue and Policy Incentives 

In Sweden, a tradable green certificate system (TGC) is in place to support renewable electricity 

production. The scheme provides support for a period of 15 years. The goal is to increase 

production from renewable energy sources to 17 TWh by the year 2016. The system is currently 

under revision to adapt to the higher goal of 25 TWh renewable electricity production by 2020. 

In addition, negotiations between Sweden and Norway are currently underway to establish a 

common system for both countries. 

Up to the year 2008, a feed-in tariff, also known as an “environmental bonus,” existed for 

onshore wind energy in parallel with the electricity certificates system. For offshore wind 

energy, the “environmental bonus” was in place up to 2009. There also has been a support 

scheme for pilot projects in place since 2003. For the period 2008-2012, € 37.1 million ($51.6 

million) is assigned to projects that are deemed interesting such as offshore wind, cold climate, 

or forest-based wind power generation. 

In the autumn of 2006, rules for the environmental impact analysis and the admission process for 

new wind power projects were simplified. Under the simplified process, wind parks up to 25 

MW only need to notify the municipality. 

A national network33 for wind use has been created as an initiative of the Swedish government, 

to spread information about the use of wind resources. The purpose of the network is to facilitate 

the development of wind power in Sweden by strengthening the country’s knowledge on 

planning and admission processes; labor, business development, and operations and maintenance 

of wind power. 

33 See http://www.natverketforvindbruk.se/ 

73 
In addition, wind power coordinators are employed to facilitate the interaction between wind 

power producers, authorities, and other actors at the local, regional, and national level. 

Typical Wind Energy Project Characteristics in Sweden 

Onshore 

Project Features 

In Sweden, full load hours for an onshore project were reported to range from 2,600-3,050. 

However, wind maps of Sweden typically show lower full load hours than the numbers reported 

by wind project developers. Therefore, the wind hours in the final submission of the Swedish 

project are on the low end of the reported range, resulting in 2,600 hours used in the calculations. 

Investment Costs 

The Swedish onshore project was defined as representative of the average cost and energy 

production of onshore projects installed in 2008. Capital costs range between €1,217/kW to 

€1,915/kW ($1,692/kW to $2,662/kW). For the modeling analysis, €1,591/kW ($2,212/kW) was 

assumed. 

Operations and Maintenance Costs 

The average fixed costs for operations and maintenance are estimated at €0.004 /kW 

($0.006/kW) and the variable costs are estimated at approximately €11/MWh ($15/MWh). 

However, the variable O&M costs can range between €7/MWh to €24/MWh ($10/MWh to 

$33/MWh). The spread for the O&M cost in the applications of the pilot projects is quite large 

and varies among developers. 

Financing Costs 

As shown in Table 6-5, a debt interest rate of 5% was assumed in the modeling analysis since 

this number is commonly reported by investors. However, an analysis of accounting statements 

of the companies investing in wind power reveals a much higher cost debt of up to 20% or more. 

It is possible that the assumed 5% debt interest rate combined with the required return on equity 

of 12%, derived from company analysis in Sweden, may lead to an underestimation of the cost of 

wind power. 

Revenue and Policy Incentives 

Wind energy projects receive two revenue streams: one from selling electricity to the market 

through long term contracts and the other from the tradable green certificate system in place. 

Both revenue streams are highly uncertain. Until 2008, the feed-in tariff bonus was also in place, 

with onshore wind receiving a small premium of €2/MWh ($3/MWh). 

Source of Data 

The data for the LCOE calculations comes from several sources, including data supplied from 

applications for the pilot support scheme mentioned above, as well as data compiled by the 

Swedish Energy Agency for internal users. Data for decommissioning cost come from Svensk 

Vindenergi (2009). Statistics on the development of wind power in Sweden come from two 

74 
       

               

 

 

 

 

 

 

 

 

publications produced annually by the Swedish Energy Agency report ES 2010:3 Vindkraft 

statistik 2009 (Wind power statistics 2009) and Vindkraft Statistik 2008. Wind hours for 2008 

are taken from the electricity certificates system. In addition, some confidential data, such as the 

financing terms, were obtained from wind power developers. Accounting data was used to get a 

clearer picture of the relevant discount rates. Expert opinions cited in the business press in 

connection with the planned stock market introduction of O2 and Arise complemented the 

picture. 

Offshore 

The largest Swedish offshore project in place as of 2008 was Lillgrunden with 110 MW. The 

Lillgrunden project was taken over by Vattenfall in 2004, and built and connected to the grid in 

2007. Lillgrunden consists of 48 Siemens 2.3 MW MKII turbines. However, thirteen wind 

turbines installed at Lillgrunden were connected to the grid before 2004. Sweden’s newest 

project is Gässlingegrund with 10 turbines of 3 MW each. This is a “near shore” project with 

foundations at between 7-13 meters in Lake Vänern. 

Table 6­3. Lillgrunden example

Lillgrunden Data 

Total height: 115 m above MSL 

Rotor diameter: 92,4 m 

Swept area: 6734 m2 

Power regulation: Variable pitch and speed 

Rotor speed: 6-16 rpm 

Tip speed: max 280 km/h 

Rotor weight 60 t 

Nacelle weight 82 t 

Tower weight: 110 t 

Est. annual production: 6.875.000 kWh 

Capacity factor: 35% 

Average wind speed: 8.5 m/s 

Table 6­4. Wind energy project features in Sweden

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Unit size MW - 2.35 N/A N/A 

Number of turbines N - 41 N/A N/A 

Production full load hours - 2,600 N/A N/A 

Economic life years - 20 N/A N/A 

Investment costs €/kW ($/kW) - 1,591(2,212) N/A N/A 

O&M costs fixed €/kW ($/kW) - 0.004 (0.006) N/A N/A 

O&M costs variable €/MWh ($/MWh) - 11(15) N/A N/A 

Decommission costs €/kW ($/kW) - 1.6 (2.22) N/A N/A 

Other costs €/MWh ($/MWh) - - N/A N/A 

75 
                

 

 

 

                   

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 6­5. Wind energy financing terms in Sweden

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Return on debt % 5 N/A N/A 

Return on equity % 12 N/A N/A 

Debt share % 87 N/A N/A 

Equity share % 13 N/A N/A 

WACC % 4.7 N/A N/A 

Loan duration years 20 N/A N/A 

Corporate tax 

rate % 28 N/A N/A 

FX rate (SEK/€) 9.42 N/A N/A 

FX rate US$/€ 1.39 

Table 6­6. Wind energy policy and revenue incentives in Sweden

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Market price electricity €/MWh ($/MWh) 50 (70) N/A N/A 

Market price certificates €/MWh ($/MWh) 25 (35) N/A N/A 

FIT revenue €/MWh ($/MWh) 2 (3) N/A N/A 

FIT policy period years 1 N/A N/A 

Upfront tax-based 

 subsidy before tax % 0% N/A N/A 

Production-based before

 tax credits €/kWh ($/kWh) N/A N/A 

Production-based before

 tax credit policy period years N/A N/A 

Depreciation period years 20 N/A N/A 

Reactive power bonus €/MWh ($/MWh) 0 N/A N/A 

Low voltage ride through 

 bonus €/MWh ($/MWh) 0 N/A N/A 

76 
  

 

 

   

         

         

Comparison of Wind Energy Costs in Sweden to the Reference Case 

As shown in Figure 6-2, the Swedish LCOE is approximately €1/MWh ($1/MWh) lower than 

the Reference Case. 

€68 ($95)

€67 ($93)

€2($3)

€5($7)

€6($8)

€2($3)

86

89

92

95

97

100

103

106

108

62

64

66

68

70

72

74

76

78

LCOE (2008 $/MWh)LCOE (2008 €/MWh)

Decreases LCOE FromReferenceCase LCOE

Increases LCOE FromReferenceCase LCOE

Reference Case LCOE

Project output

Total investment

&

decommissioning costs

Financing costs

Annual operations

&

maintenance costs

Other costs

Non‐Wind energy

related policies

Sweden LCOE

Country‐Specific Input Variables

Figure 6-2. Wind energy costs in Sweden34 

Project Output 

Full load hours in Sweden are higher than in the Reference Case, which is quite reasonable given 

the vast amounts of land available for wind power projects in comparison to some of the 

European countries in the sample. 

Investment Costs 

Investment costs in Sweden are slightly higher than in the Reference Case due to power 

development, a TGC system (in place since 2001), and the existence of NordPool (for electricity 

trading since 1995). 

Operation and Maintenance Costs 

The difference in O&M costs in Sweden compared to the Reference Case is minimal and most 

likely due to the sample and not significant. 

Financing Costs 

Financing costs are lower in Sweden compared to the Reference Case. This essentially reflects a 

lower risk level for wind power investments in Sweden, which is reasonable given the 

experience gained over time with wind power development. 

34 Data labels are rounded to the nearest whole numbers. Therefore, the sum of input variables may differ slightly 

from the total Reference Case – Country LCOE differential (due to rounding). 

77 
  

 

 

          

Revenues and Policy Incentives 

Revenues consist of three parts: 1) revenues from the sale of electricity; 2) revenues from the 

sale of green certificates; and 3) a small revenue stream from a FIT that ceased to exist after 

2009. 

As the revenue streams are market-based, they are uncertain. In the case at hand, electricity 

prices are assumed to be stable around €50/MWh ($70/MWh) and green certificate prices around 

€25/MWh ($35/MWh), though the price of green certificates rose in 2009. 

€67 ($93)

€50 ($70)

€25 ($35)

‐€8 (‐$11)

‐14

0

14

28

42

56

70

83

97

111

‐10

0

10

20

30

40

50

60

70

80

LCOE (2008 $/MWh)

LCOE (2008 €/MWh)

Sweden LCOE Revenues Wind energy policies FinancialGap

and incentives

Figure 6-3. Wind energy revenue and policy incentives in Sweden35 

35 Data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, wind energy policies 

and incentives, and the financial gap may differ slightly from the country LCOE. 

78 
             

 

 

 

 

   

 

Financial Gap 

For the average project, the costs seem to be covered quite well by the combination of market 

price of electricity and the compensation from the TGC system. 

Table 6­7. Summary of results for Sweden36

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Levelized cost of energy 

Total revenue and wind energy policies and 

incentives 

Financial gap for developer 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

-

-

-

67 (93) 

75(104) 

-8 (-11) 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

Summary of Wind Projects in Sweden 

As Table 6-7 shows, wind power projects in Sweden appear to have a relatively low weighted 

average cost of capital (WACC) as a result of low equity and debt costs. Projects are financed 

with large shares of debt financing. Loans are financed for 20 years. Although parts of these 

loans are probably of shorter duration, they are rolled over at the end of the lending period. 

Wind power has a long history in Sweden and is growing quite rapidly. This growth is necessary 

to achieve the overall goal of 25 TWh from renewable energy sources by 2020. 

36 As previously mentioned, data labels are rounded to the nearest whole numbers. Therefore, the sum of the 

revenues, wind energy policies and incentives, and the financial gap may differ slightly from the country LCOE. 

79 
 

References 

Dagens Industri, www.di.se, 2010-03-16, Storm kring vindkraftsbolag 

European Commission, National Renewable Energy Action Plans of the European Member 

States, June 2010 (European Commission 2010), at 

http://ec.europa.eu/energy/renewables/transparency_platform/action_plan_en.htm 

E24, www.e24.se, 2010-03-16, Vindkraftsbolagen anklagas för glädjekalkyler. 

Nationellt nätverk för vindbruk (national network for winduse), 

http://www.natverketforvindbruk.se/ 

Svensk Vindenergi, 2009, Vindkraftverk, – kartläggning av aktiviteter och kostnader vid 

nedmontering, återställande av plats och återvinning 

Vinkraftstatistik 2009, ES 2010:3, 2010, Swedish Energy Agency, available at 

http://www.energimyndigheten.se/Global/Press/Pressmeddelanden/Vindkraftsstatistik%202009.p 

df 

Vindkraftstatistik 2007, ES 2008:2, 2008, Swedish Energy Agency, available at 

http://www.energimyndigheten.se/en/ 

80 
 

Chapter 7: Switzerland 

Overview of Wind Industry in Switzerland 

The following chapter describes onshore and offshore wind energy project and cost 

characteristics in Switzerland, specifically the assumptions used in modeling the levelized cost of 

energy (LCOE) for onshore wind technologies in 2008. Since Switzerland is a land-locked 

country, there are no offshore projects. Lake areas are presently excluded as wind energy sites 

for landscape protection reasons. 

Capacity, Energy Production, Near-Term Targets 

The installed wind capacity onshore has increased from 2 MW in 1996 to approximately 14 MW 

at the end of 2008. The annual wind energy production has risen from 1.8 GWh (2000) to 20.20 

GWh (2008). As a comparison, the total electricity demand in 2008 amounts to 58.7 TWh. From 

projects which are currently in an advanced stage of planning, a projected capacity of 65 MW is 

expected for 2012. Federal energy policy has set an objective of 400MW capacity for 2030. 

0 

5 

10 

15 

20 

25 

30 

35 

40 

0 

50 

100 

150 

200 

250 

300 

350 

400 

Annual Capacity Additions (MW) 

Cumulative Capacity (MW)

Cumulative Capacity - Onshore (left axis) 

Annual Capacity Additions (right axis) 

Installed

Before 2000

200020012002200320042005200620072008

2012 

Projection

2030 

Objective 

Source: wind-data.ch and Federal Office of Energy 

Figure 7-1. Cumulative and annual wind installations in Switzerland 

Table 7-1 presents historical and projected cumulative wind energy installed in Switzerland. 

81 
           

 

           

 

Table 7­1. Cumulative MW installed in Switzerland

Installed 

Before Projected Objective 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2012 2030 

Onshore 2.8 2.8 4.51 4.55 4.56 8.66 11.6 11.6 11.6 13.6 17.6 65 400 

Source: wind-data.ch and Federal Office of Energy 

Table 7-2 shows historical and projected annual capacity additions. 

Table 7­2. Annual MW installed in Switzerland

Installed 

Before Projected Objective 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2012 2030 

Onshore 2.8 0.0 1.70 0.65 0.01 3.50 2.90 0.02 0.00 2.00 4.00 15.0 400 

Source: wind-data.ch and Federal Office of Energy 

Revenue and Policy Incentives 

Since 2008, a feed-in tariff (FIT) system similar to that of Germany is in force. The FIT is 

designed to cover the estimated LCOE. Included in the FIT are the electricity market price and 

the value of the green electricity. For wind energy, the FIT in Switzerland is fixed between 

€110/MWh ($153/MWh) and €130/MWh ($181/MWh). 

Typical Wind Energy Project in Switzerland 

Onshore 

Project Features 

A wind farm in the Jura Mountains (1,000-1,200 meters above sea level), with 6 turbines of 2 

MW, is used as the Swiss reference project for the cost calculations. Most of the wind projects in 

Switzerland are comprised of 2 MW turbines, with a typical rotor diameter of 82 m and a typical 

hub height of about 80 m. In some regions, the dimensions of the rotor and the tower height are 

limited by accessibility restrictions. In these regions, turbines with a rated power of 800-1000 

kW and a typical hub height of 40-60 meters are used. 

Investment Costs 

Typical project specific investment costs in Switzerland amount to €1,790/kW ($2,488/kW). 

The percentage of investment cost for a turbine in Europe is, on average, around 76%. In 

Switzerland, however, this share ranges between 55 and 68%. This difference is attributed to the 

difficult accessibility of many wind sites and the high labor costs in Switzerland, which result in 

comparatively high balance of plant costs. 

Operations and Maintenance Costs 

Given that Switzerland has little experience with operational costs, we have compared the 

available local data with O&M costs published by EWEA. Based on these investigations, 

variable O&M costs in Switzerland are assumed at €31/MWh ($43/MWh). 

82 
       

 

Financing Costs 

The following financing costs have been used for the cost calculations in Switzerland: 

Table 7­3. Financing cost calculations

Market interest rate 5% 

Required return on equity 7% 

Equity share 30% 

Economic life 20 yr 

Depreciation period 20 yr 

Inflation 0% 

Loan duration 20 yr 

Corporate tax rate (OECD) 21% 

Revenue and Policy Incentives 

There are two mutually exclusive revenue systems for producers of renewable electrical power in 

Switzerland. 

The first revenue system is the FIT system, which is the base of the following cost calculations. 

This form of remuneration applies to the following technologies: hydropower (up to 10 

megawatts), photovoltaics, wind energy, geothermal energy, biomass, and waste material from 

biomass. The tariffs on electricity from renewable energy sources (green power) are specified 

based on reference facilities for each technology and output category, and they are designed to 

cover the LCOE for each technology. Remuneration is applicable for a period of between 20 and 

25 years, depending on the technology. A gradual downward curve is foreseen in these tariffs 

due to anticipated technological progress and the increased deployment of these technologies 

into the market. Tariff reductions will only apply to registered production facilities, which will 

receive remuneration through a constant tariff for the entire period of remuneration. Producers 

who decide in favor of the FIT system option cannot simultaneously sell their green power on the 

electricity market. 

The second revenue system is the green electricity market. Producers outside the FIT system 

may sell their electricity on the market. Typically, their revenue will be the electricity market 

price plus a green power premium negotiated between the producer and the purchasing utility. 

Source of Data 

Wind energy capacity data: Swiss Wind Energy Association “Suisse Eole”. 

Investment and O&M Cost data: Survey of wind energy projects planned in 2008 

Financing Costs: FIT calculations, Swiss Federal Office of Energy Model Input 

Assumptions 

Tables 7-4 through 7-6 provide the modeling assumptions used in the LCOE estimation for 

onshore wind energy in Switzerland. 

83 
             

 

 

             

 

 

 

 

 

 

 

 

 

                 

 

 

 

 

 

 

 

 

 

Table 7­4. Wind energy project features in Switzerland

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Unit size MW - 2 N/A N/A 

Number of turbines N - 6 N/A N/A 

Production (full load hours) - 1’750 N/A N/A 

Economic life Years - 20 N/A N/A 

Investment costs €2008/kW ($/kW) - 1,790 (2,488) N/A N/A 

O&M costs fixed €/kW-year ($/kW-year) - - N/A N/A 

O&M costs variable €/MWh ($/MWh) - 31 (43) N/A N/A 

Decommission costs €/kW ($/kW) - - N/A N/A 

Table 7­5. Wind energy financing terms in Switzerland

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Return on equity % - 7 N/A N/A 

Return on debt % - 5 N/A N/A 

Equity share % - 30 N/A N/A 

Debt share % - 70 N/A N/A 

Loan duration years - 20 N/A N/A 

Corporate tax rate % - 21 N/A N/A 

FX rate CHF/€ - 0.67 N/A N/A 

FX rate $US/€ - 1.39 N/A N/A 

Table 7­6. Wind energy policy and revenue incentives in Switzerland

Onshore

2007 

 Onshore 

2008 

Offshore 

2007 

Offshore 

2008 

Market price electricity €/MWh ($/MWh) 

FIT revenue €/MWh ($/MWh) 

FIT policy period years 

Upfront tax-based % 

 subsidy before tax 

Production-based before €/MWh($/MWh) tax credits 

Production-based before 

years tax credit policy period 

Depreciation period years 

Reactive power bonus €/MWh ($/MWh) 

Low voltage ride through bonus €/MWh ($/MWh) 

Market Certificates €/MWh ($/MWh) 

­

125 (174) 

20 

-

-

-

20 

-

-

Variable* 

N/A 

N/A

N/A

 N/A 

N/A 

N/A 

N/A

N/A

N/A

N/A

N/A 

N/A 

N/A 

N/A

N/A

N/A

 N/A 

N/A 

N/A 

N/A 

* negotiable between the producer and the purchaser 

84 
 

 

   

         

         

120 167

Unique Aspects of Wind Projects in Switzerland 

The production costs for wind energy in Switzerland are estimated at €120/MWh ($167/MWh), 

which is €58/MWh ($81/MWh) higher than in the Reference Case. 

Cost Comparison 

130 181

90

€68 ($95)

€120 ($167)

€29($40)

€19($26)

€11($15) €16($22)

€1($1)

Decreases LCOE FromReferenceCase LCOE

Increases LCOE FromReferenceCase LCOE

125

80 111

110 153

LCOE (2008 €/MWh)LCOE (2008 $/MWh)

100 139

70 97

60 83

50 70 Reference Case LCOE Project output Total investment

&

decommissioning costs

Financing costs

Annual operations

&

maintenance costs

Other costs

Non‐Wind energy

related policies

Switzerland LCOE

Country‐Specific Input Variables

Figure 7-2. Wind energy costs in Switzerland compared to the Reference Case37 

Project Output 

The production of the Swiss project is considerably smaller than the production of the Reference 

Case. This is due to a moderate wind regime (1,750 full load hours). 

Investment Costs 

The total investment and decommissioning costs are higher in Switzerland than in the Reference 

Case. The difficult and complex accessibility of many sites and the high labor costs are the 

principal causes of high specific costs. The projects in Switzerland are small projects and, 

consequently, they receive lower discounts when purchasing wind turbines compared to larger 

projects. 

Operations and Maintenance Costs 

The operation and maintenance costs in Switzerland are higher than in the Reference Case. Icing 

and turbulence can cause problems to the plants and, consequently, more maintenance is 

required. There is little experience related to O&M costs in Switzerland. 

37 Data labels are rounded to the nearest whole numbers. Therefore, the sum of input variables may differ slightly 

from the total Reference Case – Country LCOE differential (due to rounding). 

85 
  

 

          

0

120

Financing Costs 

The finance costs in Switzerland are lower than in the Reference Case. The return on equity is set 

at 7%, though most projects are financed by utility companies that do not invest for financial 

reasons. Utility companies’ main concern is the growing demand for green electricity. 

Revenues and Support Mechanisms 

FIT for wind energy in Switzerland ranges from €110-130/MWh ($153-181/MWh) with 

€125/MWh ($174/MWh) used in the modeling analysis. For a more detailed description of the 

revenues, see the “Revenue and Policy Incentives” paragraph. There are no other financial 

support mechanisms at the federal level. 

There are support mechanisms for renewable electricity on the state level. In most states, they are 

focused on photovoltaic projects and they do not support wind energy. 

130
 181
 

110
 

€120 ($167) €42 ($58) €125 ($174)

‐€5 (‐$7)

153
 

100
 139
 

90
 125
 

LCOE (2008 €/MWh)80
 

70
 

60
 

50
 

40
 

30
 

20
 

10
 

111
 

97
 

83
 

70
 

56
 

42
 

28
 

14
 

LCOE (2008 $/MWh)

‐10 ‐14

Switzerland LCOE Revenues Wind energy policies FinancialGap

and incentives

Figure 7-3. Wind energy revenue and policy incentives in Switzerland38 

Financial Gap 

Swiss policy incentives are designed to cover LCOE. Figure 7-3 shows that, for a typical wind 

energy project in Switzerland, the LCOE is covered by the FIT. 

38 Data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, wind energy policies 

and incentives, and the financial gap may differ slightly from the country LCOE. 

86 

0

167
             

 

 

 

Summary 

Table 7­7. Summary of wind projects for Switzerland39

 Onshore Onshore Offshore Offshore

 2007 2008 2007 2008 

Levelized cost of energy 

Total revenue and wind energy policies and 

incentives 

Financial gap for developer 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

-

-

-

120 (167) 

125 (174) 

-5 (-7) 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

39 As previously mentioned, data labels are rounded to the nearest whole numbers. Therefore, the sum of the 

revenues, wind energy policies and incentives, and the financial gap may differ slightly from the country LCOE. 

87 
 

References 

Die Website für Windenergie-Daten der Schweiz, Accessed at www.wind-data.ch 

Erläuternder Bericht zur Revision der Anhänge EnV, Bundesamt für Energie, 2.10.2009 

Swiss Energy Act of June 26, 1998, http://www.admin.ch/ch/d/sr/c730_0.html 

Swiss Energy Ordinance of December 7, 1998, http://www.admin.ch/ch/d/sr/c730_01.html 

88 
 

 

Chapter 8: United States 

Wind Energy in the United States 

The following chapter describes onshore and offshore wind energy project and cost 

characteristics in the United States, specifically the assumptions used in modeling the levelized 

cost of energy (LCOE) for onshore wind technologies in 2008. Offshore wind energy is only 

briefly described due to the lack of historical development in the U.S. This chapter also presents 

the results of 2008 U.S. cost analysis in comparison to the Reference Case presented in Chapter 

1. 

Capacity, Energy Production, Near-Term Targets 

Wind energy capacity in the United States expanded from approximately 2.5 gigawatts (GW) of 

cumulative installations in 2000 to over 25 GW by year-end 2008 (Figure 8-1). In each year 

since 2005, the wind industry recorded record U.S. annual installations with 8.5 GW of new 

capacity added in 2008.40 Wind energy accounted for 42% of all new U.S. electrical generating 

capacity in 2008 and in an average year, the cumulative wind energy capacity could supply 

approximately 1.9% of total U.S. electricity consumption (Wiser and Bolinger 2009). As of 

2008, all U.S. wind capacity was constructed onshore, however, several offshore wind projects 

were in the permitting and planning stages. 

40 In fact, this trend continued in the U.S in 2009 with just over 10 GW of wind capacity additions (AWEA 2010). 

For this report, wind energy capacity is generally discussed through 2008, the year used in the cross-country 

comparisons. 

89 
 

 

Figure 8-1 provides historical cumulative and annual U.S. wind energy installations, a 2012 wind 

energy projection, and a 2030 potential wind energy scenario. 

0 

5 

10 

15 

20 

25 

30 

35 

0 

50 

100 

150 

200 

250 

300 

350 

Annual Capacity Additions (GW) 

Cumulative Capacity (GW)

Cumulative Capacity - Offshore (left axis) 

Cumulative Capacity - Onshore (left axis) 

Annual Capacity Additions (right axis) 

2012 Projection 

2030 Scenario 

Installed 

Before 2000

200020012002200320042005200620072008

2012

Projection

2030 

Scenario 

Sources: AWEA 2009 (2000-2008), DOE 2008 (2030 scenario), EIA 2009 (2012 projection) 

Figure 8-1. Cumulative and annual U.S. wind installations 

The U.S. does not have explicit wind energy targets. Alternative data points to country wind 

energy targets are therefore shown in Figure 8-1. In the near-term, the Energy Information 

Administration (EIA) projects approximately 10 GW of U.S. wind capacity additions in 2012 – a 

modest increase over actual 2008 installations (EIA 2009).41 Longer-term, a recent study 

analyzed a potential wind energy scenario where 20% of projected U.S. electricity demand 

would be met with wind energy by 2030 (DOE 2008). The study estimated that 305 GW of wind 

capacity would be required to meet the 20% milestone – the total comprised of both onshore and 

offshore wind energy technologies. In the study, total annual capacity additions ramp up to 

approximately 16 GW per year by 2018. 

41 As previously noted, just over 10 GW of wind energy installations were developed in 2009 (AWEA 2010). 

90 
               

 

               

 

 

 

 

Table 8-1 presents historical and projected cumulative wind energy installed in the U.S. 

Table 8­1. U.S. cumulative wind energy installations (GW)

Installed 

Before 2012 2030 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 Projection Scenario 

Onshore 2.5 2.6 4.3 4.7 6.4 6.8 9.2 11.7 16.9 25.5 59.5 251 

Offshore 0 0 0 0 0 0 0 0 0 0 0 54 

Sources: AWEA 2009, DOE 2008 (2030 scenario), EIA 2009 (2012 projection). 

Table 8-2 shows historical and projected annual capacity additions. 

Table 8­2. U.S. annual wind energy installations (GW)

Installed 

Before 2012 2030 

2000 2000 2001 2002 2003 2004 2005 2006 2007 2008 Projection Scenario 

Onshore 

Offshore 

N/A 

N/A 

0.1

0 

 1.7

0 

 0.4 

0 

1.7

0 

 0.4

0 

 2.4 

0 

2.5 

0 

5.2 

0 

8.6 

0 

10.3 

0 16 

Sources: AWEA 2009, DOE 2008 (2030 scenario), EIA 2009 (2012 projection). 

Revenue and Policy Incentives 

The primary sources of revenue for wind energy in the United States are sales of electricity and 

renewable energy market certificates (RECs). The economic value of the electricity and REC 

sales varies greatly from project to project based on regional, market, and other distinctions. 

Wind energy in the United States is supported by the federal government principally through tax 

incentives. For wind energy technologies in 2008, these incentives include an inflation-adjusted 

production tax credit (PTC) and eligibility for accelerated depreciation of specific capital 

equipment (Schwabe et al. 2009). 

Prior to 2004, the PTC expired on several occasions, though in each instance it was eventually 

renewed. This resulted in a boom and bust cycle of annual development from 2000-2004. Post 

2004, however, the PTC has been in continuous force resulting in record U.S. annual 

installations each year from 2005 through 2009 (AWEA 2010). 

The value of the federal tax incentives is a significant economic benefit for eligible renewable 

energy technologies. For wind projects on a present value basis, the combined benefit of the PTC 

and accelerated depreciation is estimated at 35% of a baseline project’s installed costs (Bolinger 

2010). On some occasions, the combined economic benefit of the PTC and accelerated 

depreciation can equal or exceed the system’s revenues from the sale of electricity and RECs 

(Harper et al. 2007).42 

Typical Wind Energy Project in the United States in 2008 

The following section describes 2008 U.S. wind energy project characteristics. For comparison 

to other countries in this report, average or generally representative U.S. project characteristics 

42 This will be dependent on a number of location-specific factors that are constantly changing including the amount 

of wind generated, electric generation price, and local REC prices. 

91 
 

 

are presented below. However, precise wind energy project costs and attributes are locationspecific and vary considerably for U.S. installations. 

Onshore 

Project Features 

The average size of installed wind projects in the U.S. has ranged from approximately 35 MW in 

1998-1999 to 120 MW in 2007, with an average installed project size of 83 MW observed in 

2008 (Wiser and Bolinger 2009). Wind turbines installed in the United States over time have 

ranged in capacity from less than 0.5 MW to 3 MW, with an average turbine size of 1.67 MW for 

projects installed in 2008 (Wiser and Bolinger 2009). The most common turbine in the United 

States has a rated capacity of 1.5 MW, a rotor diameter of 77 m and a hub height of 80 m (GE 

2010, Wiser and Bolinger 2009). 

Project Performance 

The quality of wind resource varies greatly from project to project, but overall the United States 

has an excellent wind regime. Full load hours for U.S. onshore wind projects range widely, 

approximately 1800-4400 hours, with a capacity-weighted average of 3,066 hours observed in 

2008 (Wiser and Bolinger 2009).43 It is important to note that the estimated full load hours are 

based on projects installed in 2007 that operated during 2008 – and not on total U.S. wind 

resource potential. 

Investment Costs 

Onshore wind project investment costs in the United States have been steadily increasing in 

recent years. For projects installed in 2008, investment costs ranged from roughly a minimum of 

€1,000/kW to more than €1,800/kW ($1,400/kW to $2,500/kW) with a capacity-weighted 

average of €1,378/kW ($1,915/kW) (Wiser and Bolinger 2009).44 Wind turbine transaction 

prices also have been increasing in recent years; however, the decrease in demand from the 2008 

financial crisis and accompanying economic slowdown reportedly has offered some turbine price 

and supply relief (Wiser and Bolinger 2009, Bolinger 2010). 

Operations and Maintenance Costs 

Operations and maintenance costs in the United States include both a fixed and a variable 

component and can be expressed in either manner. Capacity-based costs (€/kW) may include 

insurance, property taxes or various other facility costs; production-based costs (€/MWh), 

regular and unscheduled maintenance charges, equipment replacement or rebuilding, productionbased land-lease payments, and other costs. In the United States, data for O&M costs are limited 

in availability and quality. As such, estimates of O&M costs are approximations only, and 

anecdotal evidence suggests that O&M costs, including premature component replacements, may 

be under-represented in the reported data. Furthermore, future O&M cost estimates may increase 

somewhat as turbines age or warranty periods expire. 

For wind energy projects installed in the 2000s, Wiser and Bolinger estimate the 2000-2008 

capacity-weighted average O&M cost of €5.8/MWh ($8.0/MWh) (Wiser and Bolinger 2009). 

43 Based on a 35% capacity factor. 

44 All costs expressed in 2008 euros and dollars. Exchange rate of 1.39 $U.S/€ is used in dollar to euro conversions 

from December 31, 2008 (Federal Reserve 2010). 

92 
   

 

 

 

This O&M cost estimate, however, does not generally include property taxes. To include this 

expense, an additional €5.0/kW-year ($7.0/kW-year) estimated average property tax payment45 is 

added to the Wiser and Bolinger O&M estimate. The total O&M cost estimate with property 

taxes is €7.4/MWh ($10.3/MWh) expressed in variable terms or €22.6/kW-year ($31.4/kW-year) 

in fixed terms.46 For comparison, the 20% Wind Energy by 2030 study estimates slightly lower 

O&M costs by 2010 at approximately €6.9MWh ($9.6/MWh) (DOE 2008).47

Financing Costs 

Wind project development in the United States in 2008 was often financed with high equity 

percentages and little to no project-based debt. The use of high equity percentages was due in 

part, to the historical intermittency of the production tax credit incentive. Debt financing could 

lengthen and complicate the financing stage of wind project development and risk missing 

economically valuable federal PTC deadlines (Harper et al. 2007). 

The move away from debt financing also was due to the project development team’s desire to 

maintain “upside potential” in the output of the system (including energy and sometimes 

environmental attributes); therefore, they did not lock in wind energy contract prices. Debt 

lenders in the United States typically require predetermined energy contract prices for the full 

output of the system (Cory and Schwabe 2009). Moreover, debt financing of wind projects in 

late 2008 was considerably more difficult to obtain than it was prior to the financial crisis 

because of reduced lending activities and risk aversion in the global credit markets (Schwabe et 

al. 2009). 

For the modeling analysis, 100% equity investment is assumed, which was a recurring though 

not exclusive financing arrangement in the United States in 2008 (and less common 

internationally). In the modeling analysis, the required return on equity in 2008 is assumed at 

7.5% (Chadbourne and Parke 2009). Note that rates of return on equity were impacted by the 

October 2008 financial crisis that widely increased the cost of equity financing, reportedly by 

100-200 basis points (Chadbourne and Parke 2009, Wiser and Bolinger 2009). 

Revenue and Policy Incentives: 

The main revenue sources for U.S. onshore wind projects are 1) electricity and renewable energy 

certificate sales, through either long-term contracts or market-based prices, 2) the monetization 

of the federal production tax credit, and 3) the accelerated depreciation of certain capital 

equipment. In the United States, revenue from electricity and RECs varies greatly by region and 

market, (electricity: regulated vs. unregulated and RECs: voluntary vs. compliance towards 

renewable energy quota mandates). In the modeling analysis, an equally weighted-average wind 

energy price estimate is assumed between long term contract prices (inclusive of both electricity 

and RECs) and wholesale market prices (electricity only) plus RECs separately.48 The 2008 

average wind energy price is estimated at approximately €41.9/MWh ($58.2/MWh).49 

45 Average property tax payment estimated from an internal NREL database. 

46 Based on 2008 U.S. project capacity and full load hours input assumptions. 

47 Estimate converted to 2008$ based on U.S. project capacity and full load hours input assumptions in 2008. 

48 Project owners of the 43% of wind power capacity added in 2008 included some merchant risk, while power 

marketers, who may also take merchant risk, purchased an additional 7% of new wind power capacity in 2008 

93 
 

 

 

 

 

 

The inflation-adjusted production tax credit was valued at approximately €15.1/MWh 

($21.0/MWh) in 2008 (Wiser and Bolinger 2009). The accelerated depreciation of certain capital 

costs occurs over a schedule of six years, which is modeled at 20%, 32%, 19.2%, 11.5%, 11.5%, 

5% in years 1-6 respectively.50 

Sources 

Data for the onshore modeling analysis was derived from a number of sources with preference 

given to publicly available resources whenever possible. A full listing of all data sources 

presented can be found in the reference section of this chapter. A more detailed description of the 

data for project features, project performance, investment costs, operations and maintenance 

costs, among other variables, can be found in the appendix of Wiser and Bolinger 2009. 

Offshore 

To date, no utility-scale offshore wind projects are operational or under construction in the 

United States. The 20% Wind Energy by 2030 report indicates that commercial offshore wind 

will be initially developed in the United States between 2012 and 2018 using shallow water 

technology, and primarily concentrated off the East Coast (DOE 2008). Estimates of anticipated 

offshore wind project features are included here for reference; however, due to the lack of 

operational offshore wind projects in the United States, these estimates are not included in the 

levelized cost of energy modeling analysis. 

Project Features 

U.S. offshore wind turbines are projected to be larger and operate in a better wind regime than 

onshore-based projects. For example, the Cape Wind offshore wind project that is under 

consideration in Massachusetts has announced planned turbine sizes of 3.6 MW (Capewind 

2010). Full load hours are projected to range from 3,000 to approximately 4,800 hours (DOE 

2008). 

Investment Costs 

Offshore wind investment cost estimates vary considerably and have been on an upward 

trajectory since the mid-2000s. Recent examination of investment costs for offshore wind 

projects proposed in the United States and Europe indicate an investment cost of approximately 

€3,100/kW ($4,300/kW). This represents projects planned for construction in the next few 

years.51 The U.S. Offshore Wind Collaborative, meanwhile, anticipates offshore wind project 

costs to be as high as €3,300/kW ($4,600/kW) (USOWC 2009). 

Operations and Maintenance Costs 

As there are no operational offshore wind projects in the United States, there is a great deal of 

uncertainty in the projections of operations and maintenance costs. Although there is little 

(Wiser and Bolinger 2009). For this analysis, it is assumed that 50% of new wind energy in 2008 used market-based
 

pricing (i.e., merchant), while the remaining 50% used long term contract prices.

49 The following assumptions for 2008 prices were interpreted from Wiser and Bolinger 2009 and include: 

(1) Long term wind energy contract prices (electricity + RECs) = $51.5/MWh, 

(2) Wholesale spot market prices = $60/MWh, and 

(3) Renewable energy certificates = $5/MWh. 50 This depreciation schedule is based on the mid-year convention and ignores the 50% bonus depreciation that was 

available in 2008 and 2009. 

51 Estimate based on internal NREL analysis. 

94 
 

 

 

published data, recent estimates of operations and maintenance costs for offshore wind projects 

proposed in the United States and Europe indicate a total cost of approximately (€13.7/MWh) 

($19/MWh).52 

Financing Costs 

Due to the perceived risks and lack of development or operational history of offshore wind 

energy in the United States, financing costs for the first few offshore projects are likely to be 

very high compared to onshore projects. Financing sources for offshore wind may include 

investors with higher risk tolerances (i.e., private equity funds) rather than traditional investors in 

onshore wind projects (i.e., insurance companies). For example, the required return for private 

equity fund investments may range from 25% to 35% for demonstrator technologies (Justice 

2010). The U.S. federal government also offers federal loan guarantees that could help secure 

less expensive debt financing for commercial and innovative renewable energy technologies 

(offshore technologies might qualify for either). Under current law, however, the loan guarantee 

program is limited in funding availability and applicant eligibility (DOE 2010). 

Federal and state level incentives available to onshore wind projects are assumed to be applicable 

to offshore as well. Federal incentives principally include the aforementioned PTC and 

accelerated depreciation of certain capital equipment. Individual states, primarily off the East 

Coast and Great Lakes region of the United States, have taken a variety of approaches and 

initiatives to facilitate offshore wind project development in their respective jurisdictions 

(USOWC 2009). 

Sources 

The primary sources of data for offshore wind characteristics include the “20% Wind Energy by 

2030: Increasing Wind Energy’s Contribution to U.S. Electricity Supply” report (DOE 2008), 

“U.S. Offshore Wind Energy: A Path Forward” by the U.S Offshore Wind Collaborative, and 

various press releases regarding offshore wind development in the United States, though caution 

is exercised with the latter. 

Model Input Assumptions 

Tables 8-3 through 8-5 provide the modeling assumptions used in the levelized costs of energy 

analysis that follows. All cost assumptions are representative of wind projects in 2007 and 2008, 

and are expressed in 2008 euros and dollars. For a detailed description of the model and 

methodology, please see Chapter 1. 

52 Estimate based on internal NREL analysis. 

95 
                   

 

 

 

 

                 

 

 

 

 

 

 

   

 

 

 

 

 

 

 

Table 8­3. Wind energy project features in the U.S.

Onshore Onshore Offshore Offshore 

200753 2008 200754 2008 

Unit size 

Number of turbines 

Production55

Economic life 

Investment costs 

O&M costs fixed56 

O&M costs variable57 

Decommissioning costs 

Other costs 

MW 

N 

 Full load hours 

Years 

€/kW ($/kW) 

€/kW ($/kW) 

€/MWh ($/MWh) 

€/kW ($/kW) 

€/MWh ($/MWh) 

1.65 

73 

2,891 

20 

1,241 (1,725) 

5.0 (7.0) 

5.8 (8.0) 

0 

0 

1.67 

50 

3,066 

20 

1,378 (1,915) 

5.0 (7.0) 

5.8 (8.0) 

0 

0 

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Sources: Wiser and Bolinger 2008, Wiser and Bolinger 2009. 

Table 8­4. Wind energy financing terms in the U.S.

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Return on debt 

Return on equity 

Debt share 

Equity share 

WACC

Loan duration 

Corporate tax rate58

FX rate59

% 

% 

% 

% 

% 

Years 

% 

 $US/€ 

N/A 

6.5 

0 

100 

6.5 

N/A 

38.9 

1.39 

N/A 

7.5 

0 

100 

7.5 

N/A 

38.9 

1.39 

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Sources: Chadbourne and Parke 2009, Harper et al. 2007, Schwabe et al. 2009. 

53As previously noted, all costs are expressed in 2008 euros and dollars. 

54 Although a range of projections for offshore wind project characteristics are provided in the previous section, 

offshore wind development is not included in the U.S. LCOE analysis. 

55 Assumptions are based on capacity factors of 33% in 2007 and 35% in 2008 (Wiser and Bolinger 2008, Wiser and
 

Bolinger 2009).

56 Due to limited annual data availability, capacity-based O&M costs are assumed to be equivalent in 2007 and
 

2008. 

57 Due to limited annual data availability, production-based O&M costs are assumed to be equivalent in 2007 and
 

2008. 

58 Note that the assumed federal and state income tax rates are 35% and 6% respectively (Harper et al. 2007). As 

state taxes are deductible from federal income, the combined effective tax rate is 38.9%. 

59 All costs are expressed in 2008 euros and dollars; therefore, the year-end 2008 $US/€ exchange rate is used for
 

both 2007 and 2008 (Federal Reserve 2010). 

96 
                      

 

 

 

 

 

 

 

 

 

Table 8­5. Wind energy revenue and policy incentives in the U.S.

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Market price electricity60 

Market price certificates61 

FIT revenue 

FIT policy period 

Upfront tax-based 

 subsidy before tax 

Production-based after 

 tax credits62 

Production-based after 

 tax credit policy period 

Depreciation period 

Reactive power bonus 

Low voltage ride through 

 bonus 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

Years 

% 

€/MWh ($/MWh) 

Years

Years 

€/MWh 

€/MWh

38.2 (53.1) 

Included above 

N/A 

N/A 

N/A 

14.4 (20.0) 

10 

6 

N/A 

N/A 

41.9 (58.2) 

Included above 

N/A 

N/A 

N/A 

15.1 (21.0) 

10 

6 

N/A 

N/A 

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Sources: Harper et al. 2007, Wiser and Bolinger 2009. 

Cost of Wind Energy Generation 

Cost Comparison 

The U.S. wind energy input parameters were used to calculate the U.S. LCOE for 2007 and 

2008. The 2008 U.S. LCOE (using all 2008 U.S. assumptions) was compared to the Reference 

Case (using all 2008 Reference Case assumptions), which is shown below. 

The country-specific input variables were incrementally substituted from their Reference Case 

assumption to their U.S. assumption, one variable at a time. This enabled an estimation of each 

variable’s impact on the Reference Case-U.S. LCOE differential. The U.S. LCOE is €3/MWh 

($4/MWh) lower than the Reference Case LCOE, which is shown in Figure 8-2. 

60 The 2007 wind energy pricing assumptions were also interpreted from Wiser and Bolinger 2009. 

61 Estimates for the market price of renewable energy certificates are included in the market price of electricity 

calculation. 

62 PTC euro conversion is rounded to the nearest tenth.
 

97 
  

 

 

 

 

   

         

         

€68 ($95)

€65 ($90)

€8 ($11)

€2 ($3)

€8 ($11)

€6 ($8)

€5 ($7)

70

75

81

86

92

97

103

50

54

58

62

66

70

74

LCOE (2008 $/MWh)LCOE (2008 €/MWh)

Decreases LCOE FromReferenceCase LCOE

Increases LCOE FromReferenceCase LCOE

Reference Case LCOE

Project output

Total investment

&

decommissioning costs

Financing costs

Annual operations

&

maintenance costs

Other costs

Non‐Wind energy

related policies

LCOE U.S.

Country‐Specific Input Variables

Figure 8-2. Wind energy costs in the U.S and the Reference Case in 200863 

Project Output: 

A wind energy project in the United States benefits from a better wind regime on average than 

represented in the Reference Case. For U.S.-based onshore projects in 2008, an average of 3,066 

full load hours is expected compared to 2,628 hours for the Reference Case. Greater project 

output in the U.S. decreases the U.S. LCOE relative to the Reference Case LCOE by 

approximately €8/MWh ($11/MWh). 

Investment Costs 

Total investment and decommissioning costs in the United States are approximately €72/kW 

($100/kW) lower than the Reference Case. Average investment costs in the U.S. in 2008 were 

€1,378/kW ($1,915/kW) compared to €1,449/kW ($2,029/kW) for the Reference Case. 

Decommissioning costs, which include the dismantling of wind energy generation equipment 

and restoration of the project site, are assumed to be implicit in the all-in investment costs. 

Therefore, lower investment costs in the U.S. decrease the U.S. LCOE relative to the Reference 

Case LCOE by approximately €2/MWh ($3/MWh). 

Financing Costs: 

Financing costs in the U.S. in 2008 are higher than the Reference Case due to the high equity 

levels (100% in 2008), and because the Reference Case primarily uses debt financing. The rate 

63 Data labels are rounded to the nearest whole numbers. Therefore, the sum of input variables may differ slightly 

from the total Reference Case – Country LCOE differential (due to rounding). 

98 
  

of return on equity for wind projects in the United States in 2008 (7.5%) is 200 basis points 

higher than the debt interest rate in the Reference Case (5.5%). 

In the United States, rates of return on equity rose from 2007 to 2008 because of the loss of 

traditional tax equity investors from the financial crisis (Schwabe et al. 2009). This is also due, in 

part, to the nature of U.S. renewable energy tax incentive policies that offer similar benefits to 

other tax offsetting investments such as affordable housing, which offered returns in 2007 at 

approximately 6%, thereby setting a floor on equity investment returns (Chadbourne and Parke 

2007). Greater financing costs in the U.S. increase the U.S. LCOE relative to the Reference Case 

LCOE by approximately €8/MWh ($11/MWh). 

Operations and Maintenance Costs: 

Total operations and maintenance costs in the United States are lower than the Reference Case. 

O&M costs can be represented as either a fixed or variable costs; therefore, comparisons to the 

Reference Case are made using a converted single charge estimate expressed in variable terms. 

Total O&M cost estimates in the United States fall well under the estimate of the Reference Case 

values, at €7/MWh ($10/MWh) vs. €13/MWh ($18/MWh) respectively. Estimates should be 

viewed with some caution however, as the U.S. wind industry has reportedly faced significant 

and ongoing challenges in projecting O&M cost estimates and reported data is often incomplete. 

Some evidence suggests that O&M costs decrease with project size (Wiser and Bolinger 2009). 

This may contribute to the lower U.S O&M estimate compared to the Reference Case (as U.S. 

project sizes are larger than the Reference Case). O&M costs in the United States may also be 

mitigated due to warranty periods that may still be in effect for newer projects. Lower O&M 

costs in the United States decrease the U.S. LCOE relative to the Reference Case LCOE by 

approximately €6/MWh ($8/MWh). 

Other Costs 

Other costs are not modeled in the U.S. analysis separately as they are assumed to be implicit in 

the capital, financing, or the all-in O&M costs. Other costs could include low voltage ride 

through (LVRT) requirements by grid operators or reactive power costs. Fees for ancillary 

services are not typically charged directly to wind projects. 

Non-Wind Energy Related Policy Impacts 

Non-wind energy related policies increase the cost of wind energy in the United States compared 

to the Reference Case. Non-wind energy related policies include 1) the corporate tax rate and 2) 

the deduction of interest payments from corporate taxable income. The United States has a 

higher effective national corporate tax rate (38.9%) than the Reference Case (30%), which 

increases the U.S. LCOE. Additionally, because 100% equity financing is assumed, the U.S. 

LCOE is not reduced by the deduction of interest payments on taxable income. Non-wind 

energy related policies in the U.S. increase the U.S. LCOE relative to the Reference Case LCOE 

by approximately €5/MWh ($7/MWh). 

Revenues and Wind Energy Policies and Incentives 

The model’s financial gap calculation is used to compare the value of the U.S. revenue variables 

(electricity and RECs) to the wind energy policies and incentives variables. The financial gap is 

99 
  

 

          

first calculated without any revenue or wind energy policies and incentives variables. Then, the 

financial gap is recalculated with just the revenue variables included. Lastly, the financial gap is 

recalculated again with both the wind energy policies and incentives variables included. This 

incremental process identified the relative value of revenue variables to the wind energy policies 

and incentives variables. 

Figure 8-3 compares the revenue variables to the wind energy policies and incentives variables, 

and together, how they constitute the U.S. LCOE. Of the €65/MWh ($91/MWh) U.S. LCOE in 

2008, approximately €41/MWh ($57/MWh) is covered by revenue sources (electricity and REC 

sales) while €24/MWh ($33/MWh) is covered by specific wind energy policies and incentives 

(PTC and the acceleration of the depreciation schedule). In relative terms, around 2/3 of the 

U.S. LCOE is covered by the revenue components while the remaining 1/3 is covered by wind 

energy policies and incentives. 

€65 ($90) €41 ($57)

€24 ($33)

‐€1 (‐$1)

‐14

0

14

28

42

56

70

83

97

‐10

0

10

20

30

40

50

60

70

LCOE (2008 $/MWh)

LCOE (2008 €/MWh)

U.S. LCOE	 Revenues Wind energy policies Financial gap

and incentives

Figure 8-3. U.S. revenues and wind energy policies and incentives in 200864 

64 Data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, wind energy policies 

and incentives, and the financial gap may differ slightly from the country LCOE. 

100 
 

                  

 

 

 

 

 

 

Financial Gap 

The financial gap in the U.S. modeling analysis is approximated at -€1/MWh (-$1/MWh). This 

suggests that on average, a wind project developer in the United States receives sufficient cash 

flow from revenue and wind energy policies and incentives (if eligible) to meet the financial 

requirements to develop the project. This is also evident by the consecutive record of annual 

wind installations from 2005-2009 when the PTC was in continuous force. Conversely, annual 

installations dramatically declined when the PTC was not in effect (AWEA 2009).65 

Summary of Wind Projects in the U.S. 

In recent years, wind energy capacity in the United States has expanded rapidly. This was a 

result of an excellent wind regime, comparatively low costs, sufficient revenue sources, and 

favorable policy incentives, when available. While all wind energy developed to date in the 

United States has been onshore, the first offshore projects in the United States are progressing. 

The costs of wind energy in the United States are generally lower than the Reference Case 

primarily due to greater energy output, lower capital costs, and lower O&M expenditures. U.S. 

federal government policy incentives for wind energy, when authorized politically, have driven 

development in many, but not all, parts of the country. Taken together, the revenue and policy 

incentives result in a near zero financial gap for a wind energy project developer. 

Table 8­6. Summary of results for the United States66

Onshore Onshore Offshore Offshore 

2007 2008 2007 2008 

Levelized cost of energy 

Total revenues and wind energy policies 

and incentives 

Financial gap for developer 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

€/MWh ($/MWh) 

58 (81) 

60 (83) 

-2 (-3) 

65 (90) 

65 (90) 

-1 (-1) 

-

-

-

-

-

-

65 See Figure 1.
 66 As previously noted, data labels are rounded to the nearest whole numbers. Therefore, the sum of the revenues, 

wind energy policies and incentives, and the financial gap may differ slightly from the country LCOE.
 

101 
References 

AWEA, (2010). “U.S. Wind Energy Industry Breaks All Records, Installs Nearly 10,000 MW in 

2009, Manufacturing Investment, Jobs Still Lag,” American Wind Energy Association (AWEA) 

news release, January 26, 2010, at http://www.awea.org/newsroom/releases/01-26­

10_AWEA_Q4_and_Year-End_Report_Release.html 

AWEA. (2009). “American Wind Energy Association Annual Wind Industry Report. Year 

Ending 2008,” American Wind Energy Association (AWEA), at 

http://www.awea.org/publications/reports/AWEA-Annual-Wind-Report-2009.pdf 

Bolinger, M. (2010). “Revealing the Hidden Value that the Federal Investment Tax Credit and 

Treasury Cash Grant Provide to Community Wind Projects,” Lawrence Berkeley National 

Laboratory technical report LBNL-2909E, January 2010, at 

http://eetd.lbl.gov/EA/EMP/reports/lbnl-2909e.pdf 

Capewind (2010). “Cape Wind Signs Agreement to Buy Siemens 3.6-MW Offshore Wind 

Turbines”, Cape Wind (Capewind) news release, March 31, 2010, at 

http://www.capewind.org/news1086.htm 

Chadbourne and Parke (2009). “Trends in Tax Equity for Renewable Energy,” Project Finance 

NewsWire, Chadbourne and Parke, January 2009, at 

http://www.chadbourne.com/files/Publication/810dde60-3c78-4a9a-9c5da5fae8014b4f/Presentation/PublicationAttachment/51fc06c5-1407-48ac-9dffa605de0f58e1/pfn0109.pdf 

Chadbourne and Parke (2007). “The Tax Equity Market,” Project Finance NewsWire, 

Chadbourne and Parke, April 2007, at http://www.chadbourne.com/files/Publication/572b04b4­

905e-48e1-8f6b-0f520c4f2615/Presentation/PublicationAttachment/573bdc6c-ff85-4f99-b4d0­

25a845907bcc/pfn0407.pdf 

Cory, K.; Schwabe, P. (2009). “Wind Levelized Cost of Energy: A Comparison of Technical and 

Financing Input Variables,” National Renewable Energy Laboratory Technical Report NREL/ 

TP-6A2-46671, October 2009, at http://www.nrel.gov/docs/fy10osti/46671.pdf 

DOE (2010). “General Loan Guarantee Program Frequently Asked Questions”, U.S. Department 

of Energy (DOE), accessed April 2010, at http://www.lgprogram.energy.gov/faq2.htm 

DOE (2008). “20% Wind Energy by 2030: Increasing Wind Energy’s Contribution to U.S. 

Electricity Supply,” U.S. Department of Energy (DOE), Office of Energy Efficiency and 

Renewable Energy, July 2008, at http://www.20percentwind.org/ 

EIA (2009). “Annual Energy Outlook 2010 Early Release with Projections to 2030,” U.S 

Department of Energy, Energy Information Administration (EIA) website, accessed February 

2010, at http://www.eia.doe.gov/oiaf/aeo/excel/aeotab_16.xls 

102 
 

Federal Reserve (2010). “Historical Rates for Euro Area”, Board of Governors of the Federal 

Reserve System website, accessed February 2010, at 

http://www.federalreserve.gov/releases/h10/hist/dat00_eu.htm 

GE (2010). “1.5 MW Wind Turbine Technical Specifications”, GE Energy (GE) website, 

accessed April 2010, at 

http://www.gepower.com/prod_serv/products/wind_turbines/en/15mw/specs.htm 

Harper, J.; Karcher, M.; Bolinger, M. (2007). “Wind Project Financing Structures: A Review & 

Comparative Analysis,” Lawrence Berkeley National Laboratory technical report LBNL- 63434, 

September 2007, at http://eetd.lbl.gov/ea/ems/reports/63434.pdf 

Justice, S. (2009). “Private Financing of Renewable Energy – A Guide for Policymakers," UNEP 

Sustainable Energy Finance Initiative, Bloomberg New Energy Finance, Chatham House, 

December 2009, at http://www.chathamhouse.org.uk/files/15542_1209_financeguide.pdf 

Schwabe, P.; Cory, K.; Newcomb, J. (2009). “Renewable Energy Project Financing: Impacts of 

the Financial Crisis and Federal Legislation,” National Renewable Energy Laboratory technical 

report NREL/TP-6A2-44930, July 2009, at http://www.nrel.gov/docs/fy09osti/44930.pdf 

USOWC (2009). “U.S. Offshore Wind Energy: A Path Forward,” U.S. Offshore Wind 

Collaborative (USOWC), October 2009, at http://eetd.lbl.gov/EA/EMP/reports/63434.pdf 

Wiser, R.; Bolinger, M. (2009). “2008 Wind Technologies Market Report,” U.S. Department of 

Energy, Office of Energy Efficiency and Renewable Energy, July 2009, at 

http://eetd.lbl.gov/ea/ems/reports/2008-wind-technologies.pdf 

Wiser, R.; Bolinger, M. (2008). “Annual Report on U.S. Wind Power Installation, Cost, and 

Performance Trends: 2007,” U.S. Department of Energy, Office of Energy Efficiency and 

Renewable Energy, May 2008, at http://www1.eere.energy.gov/windandhydro/pdfs/43025.pdf 

103 
 

Appendix A – Glossary of Variables 

Year independent variables worksheet 

Project Features 

Variable Definition Specific components included 

Project title The name of the project, for For example, German on-shore reference wind park 

comparison purposes to other wind 

parks in other countries 

Project Type The type of wind park under Onshore or offshore 

investigation. 

Number of wind Total number of wind turbines that Used to calculate the unit size and the full load 

turbines are represented in the wind park hours 

under investigation (likely a 

theoretical average wind park for 

the country). 

Rated power The rated power per turbine Used to calculate the unit size and the full load 

hours 

Rotor Diameter The diameter of the wind turbine Informational; not used in any calculations. 

rotor, in meters. 

Swept area The total area swept by the rotors. In square meters; informational – not used in any 

calculations. 

Hub Height The average height in meters Informational; not used in any calculations. While 

where the hub is located, for the this may not be used in calculations, there should 

wind park under investigation. be a direct correlation between the average hubheight wind speed and the annual electricity 

production. 

Long term average The long-term average wind speed Informational; not used in any calculations 

wind speed at hub at the hub height. 

height 

Net electricity Average annual net electricity Used to calculate the full load hours. 

production production of the wind park. 

Tax Capability Limited or unlimited. Option for the user – either the project must stand 

on its own (and absorb all tax benefits), or the 

project owner can have a parent company that can 

efficiently use all of the tax credits in that year. The 

tax credit applies to national/federal taxes only (and 

not state/municipal level). 

Currency The currency of all costs, Set to Euros, based on the representative dates for 

revenues, incentives, etc. comparison: Calendar year 2007 (December 31st 

2007) as well as Calendar year 2008 (December 

31st 2008). 

Fixed annual costs Measurement unit used for fixed Set to €/kW 

unit operations and maintenance costs 

Variable annual costs Measurement unit used for annual Set to €/kWh 

unit operations and maintenance costs 

104 
Total investment cost 

Variable Definition Specific components included 

Wind turbine The upfront cost of the wind turbine 

and generation equipment. 

Tower, rotor hub, rotor bearings, main shaft, main 

frame (supporting the drive train), gearbox, yaw 

system, pitch system, brake system, nacelle 

housing, generator, rotor blades, wind turbine 

transformer, and screws; but not including 

foundation or electrical interconnection (covered 

elsewhere). 

Wind turbine 

transportation 

The cost of transporting the wind 

turbine from the manufacturing 

factory, to the project development 

site, in preparation for erection. 

Includes shipping, railroad costs, trucking costs and 

the cost of cranes used to complete delivery of the 

turbine to the project site. 

Wind turbine 

installation 

The cost of installing the wind 

turbine during project construction. 

Includes the cost of the cranes during construction. 

Sub-total: wind 

turbine cost 

The sum total of the above 3 

wind turbine cost components 

If no cost breakdown of the above components 

is available, the total value can be added here. 

Foundations The total cost of the foundation 

necessary for the wind park. 

Includes the steel, concrete and other structural 

supports needed to support each wind turbine 

in the park. 

Internal grid Electrical grid within the wind park 

itself, necessary to connect to the 

wind park’s substation(s). 

All wires within the wind park, including the wires up 

to and between the wind park’s substation(s). If the 

substations connect to a final transformer before 

grid interconnection, it includes all the wires leading 

up to the final transformer. Includes cost of the 

primary controller (locally installed control 

equipment for a generation set to control the 

valves). Includes installation of supervisory control 

and data acquisition system (SCADA), or the wind 

farm monitoring system which allows the owner and 

the turbine manufacturer to be notified of faults or 

alarms, remotely start and stop turbines, and review 

operating statistics. 

Grid connection, grid 

code compliance 

Electrical grid required between the 

wind park’s transformer and the 

existing electrical grid that are 

needed to electrically interconnect 

the wind park. 

Wires from the wind park to the transmission 

system. This includes all additional equipment 

necessary for grid code compliance. If the wind park 

has many substations, including a final transformer, 

it just includes the wires between the final 

transformer and the grid. 

Grid reinforcement A weak grid can be reinforced by 

uprating its connection to the rest 

of the grid, in order to interconnect 

a wind park. 

Equipment necessary to reinforce the existing 

transmission grid, including transmission upgrades, 

additional controls, and any incremental equipment. 

Substations and 

transformer station 

The cost of all of the wind park’s 

substation(s) internal to the wind 

park’s grid, leading up to and 

including the final transformer. 

Before interconnection to the grid. Includes circuit 

breaker and switch. Transformer: a piece of 

electrical equipment used to step up or down the 

voltage of an electrical signal. Most turbines have a 

dedicated transformer to step up their voltage 

output to the grid voltage. 

Sub-total electrical 

net / grid 

The sum total of the above 4 

electrical grid components 

If no cost breakdown of the above components 

is available, the total value can be added here. 

105 
 

Certification 

Environmental 

The cost of certifying the wind park, 

prior to interconnection to the grid. 

The total cost of all environmental 

Includes certified engineering drawings and 

comparing the actual construction of the wind park 

to those drawings. 

Includes: 

surveys surveys required during the 

development phase of the wind 

park. These can be found in each 

country’s specific requirement for 

an Environmental Impact 

Statement 

 Pollutant potential (lubricants, etc.) 

 Sound level estimations 

 Visual impacts on landscape 

 Construction and operation impacts on 

wildlife and ecosystems 

 Specific bird and bat monitoring 

 Shadow flicker activity 

Non-infrastructure 

development subtotal 

Sum total of the above 2 noninfrastructure project development 

subcomponents. 

If no cost breakdown of the above subcomponents 

is available, the total value can be added here. 

O&M facilities The cost of building any new roads 

and facilities necessary to carry out 

O&M work. 

For wind turbine construction, regular O&M over the 

project’s life, inspection of rotor blades and for 

change-out of big components. 

Miscellaneous 

Interest payment 

Any other costs not included in the 

above project development costs. 

The total interest payment required 

Compensation to surrounding land owners. 

Usually a result of construction-level debt as well as 

before operation before project operation. a loan to make a down payment on a wind turbine. 

This variable is financial within years -1 and -2, but 

is an upfront cost in the first year of operation, at 

which point this cash flow model starts. 

Sub-total other 

project development 

costs 

Sum of above components If no cost breakdown of the above subcomponents is available, the subtotal value can 

be added here. 

Total Project 

Investment Costs 

Sum of above sub-totals for 

development components 

If no cost breakdown of the above components 

is available, the total value can be added here. 

Total decommissioning costs 

Variable Definition Specific components included 

Decommissioning, excl 

scrap value 

The cost of decommissioning a 

wind park and removing it from 

the land (including foundations). 

Cost of deconstructing the wind park and all related 

infrastructure, including cranes, dismantlement, 

shipping of materials and any necessary 

government certifications. 

Returning the land to 

the natural state 

The cost of returning the land to a 

predefined state. 

Once the project is decommissioned. 

Scrap value The value of selling the scrap 

material at the time of 

decommissioning. 

Materials in the wind park may be reused or sold for 

scrap value, including copper wire, steel, etc. 

Net decommissioning 

costs 

Sum of above components If no cost breakdown of the above components 

is available, the total value can be added here. 

106 
 

Project Operation 

Variable Definition Specific components included 

Operational time / full 

load hours, excluding 

derate 

Full load hours are the wind 

park’s average annual production 

divided by its rated power. 

This is the total full load hours and includes any 

downtime for planned and unplanned maintenance. 

The higher the full load hours, the higher the wind 

park’s production at the chosen site. 

Derate of full load 

hours 

Hours of non-operation of the 

wind park. 

Included to capture loss of production due to icing 

conditions, etc. 

Net operational 

time/full load hours 

The operational time/full load 

hours minus the derate. 

Includes total net hours of operation (i.e. 

including the derate). 

Economic life The assumed economic life of 

the project, during which the 

total project costs must be 

recovered. 

Does not include any residual life of the project, 

even if the project remains operational and in 

good working condition beyond the presumed 

economic life. 

Time horizon for cost 

calculations 

The period over which the 

levelized costs of electricity are 

calculated. 

By default, is set to economic life, unless a 

value is entered by the user. 

Financial variables 

Variable Definition Specific components included 

Loan duration The total number of years during 

which the loan must be repaid. 

Includes both principal payments and 

interest payments. 

Loan - market interest 

rate 

The amount charged by lenders for the 

use of the loan. 

Cost in the form of a percentage of the 

amount borrowed. 

Soft loan advantage The soft loan advantage is the total 

incremental discount on the debt interest 

rate. 

A soft loan provides a loan which is repaid at 

an interest rate that is lower than the going 

market rate. Values input elsewhere. 

Return on debt The interest rate that the loan will 

earn annually during the loan period. 

Percentage interest earned annually. 

Required return on 

equity, excl market 

volatility risk adder 

The rate of return required by the equity 

investor in the wind park. 

Percentage rate of return for equity. 

Market volatility risk 

adder 

Intended to capture the additional risk of 

participating in a competitive market, 

beyond the return on equity. 

Percentage adder to account for the risk of 

unexpected volatility in the market. 

Net required return on 

investment equity 

The percentage of return on equity to 

project investors (and not the 

developer) including the market 

volatility risk adder that is required 

by the equity investor. 

Takes into account the percent of return 

on equity and market volatility. 

Local equity ownership To capture any minimum local 

ownership requirements. 

Applicable in Denmark (minimum of at least 

20%). Values input elsewhere. 

Equity share, excl local 

equity ownership 

The percentage of equity contributed to 

cover the total investment cost and 

financing costs. 

Total investment cost covers the turbine, the 

supporting equipment and infrastructure, as 

well as the cost of administration and 

financing. 

Total equity share The sum of percentages of local 

equity share ownership and other 

equity share contributed to cover the 

total investment and financing costs. 

Includes total equity provided from both 

local and non-local investors. 

Debt share The percentage of debt contributed to 

cover the total investment cost and 

financing costs. 

A calculated value – based on the equity 

share entered (100% of the total project 

costs, minus the equity share). 

107 
 

Corporate tax rate – 

national or federal 

The total tax rate on the project from the 

federal/national government 

As a percentage. Values input elsewhere. 

Corporate tax ratemunicipal or state The total tax rate on the project from 

local governments. 

As a percentage – includes local 

municipalities, provinces, states, etc. Values 

input elsewhere. 

Net tax rate Sum of the federal and 

municipal/state corporate tax rates. 

As a percentage – includes federal AND 

municipalities, provinces, states, etc. 

Depreciation period The total number of years over which 

project equipment is depreciated, for 

financing, accounting and tax 

purposes. 

Value input elsewhere. 

Year dependent variables worksheet
 

Annual Costs 

Variable Definition Specific components included 

Manufacturer-provided 

maintenance 

Manufacturer-provided maintenance to 

the wind park for no additional cost the 

first one or more years of operation. 

This cost is typically included in the installed 

cost of the wind park. Therefore, this zero 

cost in the early years should be noted. 

Scheduled 

maintenance by 

internal staff 

Regularly scheduled wind park 

maintenance that is provided by the 

project owner’s staff. 

Specific, expected costs for regular service 

of the wind park by company staff. Can be 

on a fixed basis (Euro/kW), or a variable 

basis (Euro/kWh) 

External service 

contracts 

Regularly scheduled wind park 

maintenance, provided by a third-party 

service contractor. 

Specific, expected costs for regular service 

of the wind park by a service contractor. Can 

be on a fixed basis (Euro/kW), or a variable 

basis (Euro/kWh) 

Operation costs The annual cost required to operate the 

wind park. 

This covers the technical operation of the 

wind park, including SCADA. Does not 

administration (covered elsewhere). Includes 

costs of numerical weather prediction. 

Inspections Hire a third-party contractor (not the 

company itself, nor the service contact 

company) to inspect the turbine. 

This would include rotor blades reports 

(every 2-4 years), technical inspection of all 

components (every 2 years – 1 day per 

turbine). Timeframes of inspections can vary. 

Set on a Euro per kW basis. 

Unscheduled repairs Repairs and maintenance that was 

unanticipated. 

Whether resulting from equipment failure, 

weather situations or other exogenous 

incidents. 

O&M costs, fixed 

subtotal 

The sum total of the above 2 fixed 

O&M components. 

If no cost breakdown of the above 

components is available, the total value 

can be added here. 

O&M costs, variable 

subtotal 

The sum total of the above 2 variable 

O&M components. 

If no cost breakdown of the above 

components is available, the total value 

can be added here. 

Administration The cost of managing and overseeing 

the operation of the wind park. 

Includes salaries, buildings, automobiles 

(and fuel), etc. 

108 
 

Insurance The total annual cost of insurance 

that must be paid to protest against 

risks to and resulting from the wind 

park and its operation. 

Includes property, liability, workers 

compensation, environmental, 

automobile and all other insurance types 

directly related to the wind park. 

Grid charges Annual charges required to support 

interconnection with and operation of the 

system grid. 

The user can input these as either capacitybased costs, or energy costs. 

Grid costs, fixed Grid charges listed above 

Grid costs, variable Balancing costs, listed above 

Site lease The total cost paid to the landowner 

upon which the wind park is installed. 

Whether this is paid on a per turbine 

basis or a total number of Euros, it is 

entered as a total Euro cost. 

Capacity-based taxes Total annual taxes that a project pays 

that are based on project capacity - 

annual Euros per kW 

Note that percentage based taxes are 

entered as year independent variables in 

the previous worksheet. Values for 

capacity-based taxes are shown here, but 

are input elsewhere. 

Electricity consumption Self-consumption of electricity. For synchronization with the grid, unit startup, etc. The user can input these as either 

capacity-based costs, or energy costs. 

Environmental 

measurements, 

evaluations, etc. 

Annual environmental measurements 

and evaluations required to maintain the 

wind park’s permits and operation 

provisions. 

The user can input these as either capacitybased costs, or energy costs. 

Other annual costs, 

fixed subtotal 

Environmental measurement charges 

listed above 

Other annual costs, 

variable subtotal 

Electricity consumption costs, listed 

above 

Annual costs, fixed Sum of above components If no cost breakdown of the above 

components is available, the total value can 

be added here. 

Annual costs, variable Sum of above components If no cost breakdown of the above 

components is available, the total value can 

be added here. 

Other Revenues and Costs 

Variable Definition Specific components included 

Annual market 

participation fee 

The annual charge for participating in the 

competitive electricity market. 

Paid to the market agent/independent 

system operator. 

Balancing costs The total cost paid to incorporate the wind 

generation into the electric grid on an hour 

by hour basis. The incremental cost of the 

actual production in relation to the 

production forecasts. 

In Euros per kWh. Cost may be paid 

through a formal balancing market, or 

informally through back-up power. Or, 

the cost may be included in the market 

price of electricity and difficult to 

separate out. The user can input these 

as either capacity-based costs, or 

energy costs. 

Contract costs 

(transaction fees, etc) 

The annual payment required to maintain 

contracts. 

Transaction fees, etc. in terms of Euros 

per kWh. 

Subtotal other costs Sum of market participation fee, 

balancing costs and contract costs 

Reactive power Premium to facilitate the voltage control of 

the grid. 

Euros per kWh. Values input elsewhere. 

109 
Low voltage ride through Premium to contribute to the grid stability. Euros per kWh. Values input elsewhere. 

Market price electricity The average annual market price of 

electricity paid to a wind park. 

Euros per kWh generated. 

Market price certificates The average annual market price of 

renewable attributes/certificates paid to a 

wind park. 

Euros per kWh generated. May be set 

by a policy, or may be market based. 

Values input elsewhere. 

Feed-in tariff revenue The revenues from the feed-in tariff. Usually 

covers incremental payments required to 

cover the cost of the project, plus a 

reasonable return on equity. May also 

include the market price for electricity. 

Can depend on the specific location, 

size of project, and year in which the 

wind park comes into commercial 

operation. May be added to the market 

price of electricity (premium) or a total 

fixed price (that includes the cost of 

electricity). Values input elsewhere. 

Subtotal other 

revenues 

Sum of other revenues, listed above 

Policies – both year independent and year dependent 

variables 

Year independent variables 

Variable Definition Specific components included 

Upfront tax-based An upfront subsidy that is based The percentage of the upfront investment tax credit 

investment subsidy – on tax credits, before taxes are subsidy that is applied in the first year of operation, 

as a before-tax credit paid. This is therefore applied to as a percentage of total project investment costs. 

the project on a pre-tax basis. The same percentage applies for either total project 

costs ($) or installed capacity costs ($/kW). This taxbased incentive is applied before the project pays 

taxes. As such, they have a greater value to the 

project, as they effectively also lower the taxes the 

project must pay in that first year. Option for the 

user – either the project must stand on its own (and 

absorb all tax benefits), or the project owner can 

have a parent company that can efficiently use all of 

the tax credits in that year. The tax credit applies to 

national/federal taxes only (and not state/municipal 

level). 

Upfront tax-based An upfront subsidy that is based The percentage of the upfront investment tax 

investment subsidy – on tax deductions, after taxes are deduction subsidy that is applied in the first year of 

as an after-tax paid, and is therefore applied to operation, as a percentage of total project 

deduction (e.g. the project on an after-tax basis. investment costs. The same percentage applies for 

depreciation) either total project costs ($) or installed capacity 

costs ($/kW). This tax-based incentive is applied 

after the project pays taxes. Option for the user – 

either the project must stand on its own (and absorb 

all tax benefits), or the project owner can have a 

parent company that can efficiently use all of the tax 

credits in that year. The tax credit applies to 

national/federal taxes only (and not state/municipal 

level). 

Upfront cash The total value of the upfront The total value of the upfront investment subsidy, as 

investment subsidy investment subsidy, as a a percentage of total project investment costs. 

percentage of total project 

110 
investment costs. 

Soft loan advantage The soft loan advantage is the 

total incremental discount on the 

debt interest rate. 

A soft loan provides a loan which is repaid at an 

interest rate that is lower than the going market rate. 

Local equity ownership To capture any minimum local 

ownership requirements. 

Applicable in Denmark (minimum of at least 20%). 

Depreciation period The total number of years over 

which project equipment is 

depreciated, for financing, 

accounting and tax purposes. 

Corporate tax rate – 

national or federal 

The total tax rate on the project 

from the federal/national 

government 

As a percentage. 

Corporate tax ratemunicipal or state The total tax rate on the project 

from local governments. 

As a percentage – includes local municipalities, 

provinces, states, etc. 

Year dependent variables 

Variable Definition Specific components included 

Capacity-based taxes Annual Euro per kW taxes Capacity-based taxes that require annual payment 

and that change depending on the year. 

Feed-in tariff revenue 

(e.g. production based 

incentives) 

The revenues from the feed-in 

tariff or production based 

incentive. Usually covers 

incremental payments required to 

cover the cost of the project, plus 

a reasonable return on equity. 

May also include the market price 

for electricity. 

Can depend on the specific location, size of project, 

and year in which the wind park comes into 

commercial operation. May be added to the market 

price of electricity (premium) or a total fixed price 

(that includes the cost of electricity). Countries with 

time dependent tariff (e.g. Germany) should enter 

yearly values – even if they are at the same level for 

most of the years. 

Feed-in tariff policy The total time period during which The policy period cannot be longer than the 

period feed-in tariff or production assumed economic life of the project. For a single 

subsidies are paid. country, there may be different FIT payment levels, 

over different periods of time. The total FIT policy 

period should be entered here. 

Production-based 

before-tax credits 

Production-based (i.e. per kWh) 

tax credits intended to subsidize 

wind generation, applied before 

taxes. This is therefore applied to 

the project on a pre-tax basis. 

These production-based tax credits (Euros per 

kWh) are applied before the project pays taxes (on 

a pre-tax basis). As such, they have a greater value 

to the project, as they effectively also lower the 

taxes the project must pay. Option for the user – 

either the project must stand on its own (and absorb 

all tax benefits), or the project owner can have a 

parent company that can efficiently use all of the tax 

credits in that year. The tax credit applies to 

national/federal taxes only (and not state/municipal 

level). 

Production-based The total time period during which The policy period cannot be longer than the 

before-tax credit: policy annual before-tax credits are assumed economic life of the project. 

period paid. 

Production-based after- Production-based (i.e. per kWh) These production-based tax deductions (Euros per 

tax deductions tax deductions intended to kWh) are applied after the project pays taxes (on a 

subsidize wind generation, pre-tax basis). Option for the user – either the 

applied after taxes. This is project must stand on its own (and absorb all tax 

therefore applied to the project on benefits), or the project owner can have a parent 

an after-tax basis. company that can efficiently use all of the tax credits 

in that year. The tax credit applies to 

111 
national/federal taxes only (and not state/municipal 

level). 

Production-based aftertax deductions: policy 

period 

The total time period during which 

annual before-tax credits are 

paid. 

The policy period cannot be longer than the 

assumed economic life of the project. 

Reactive power bonus Premium to facilitate the voltage 

control of the grid. 

Euros per kWh 

Low voltage ride 

through 

Premium to contribute to the grid 

stability. 

Euros per kWh 

Market price certificates The average annual market price 

of renewable attributes/ 

certificates for the wind park, 

whether set by a market or set by 

a government policy. 

Euros per kWh generated. The user should enter 

the blended weighted average market price for all 

certificates sold into different markets (i.e. at 

different market prices). 

Accelerated 

Depreciation 

The schedule of depreciating the 

value of the equipment, for 

financing, accounting and tax 

purposes. 

The amount of depreciation taken each year is 

slightly higher than the earlier years of an asset’s 

life. Set as % of total initial investment, on an annual 

basis. Does not have to be linear. 

Depreciation period The total number of years over 

which project equipment is 

depreciated, for financing, 

accounting and tax purposes. 

The model expects the user to define the years and 

rate at which a project’s value is depreciated. If a 

country uses a methodology where the remaining 

value is depreciated in each subsequent year, the 

user will have to approximate the depreciation 

schedule and values through a proxy. 

Output variables

Variable 

Financial gap 

Definition 

The financial gap that is required 

to finance a project 

Specific components included 

The total cost (including financing costs), minus 

revenues and incentives needed to meet the 

required return on equity investment. Euros per 

MWh generated. 

Levelized electricity 

generation cost 

The present day average cost per 

kWh produced by the wind park 

over the economic life of the wind 

park. 

Includes all costs (investments, reinvestments, 

operation and maintenance), revenues, incentives 

and financing costs. Levelized costs are calculated 

using the discount rate and the turbine lifetime. 

112 
F1147-E(10/2008) 

REPORT DOCUMENTATION PAGE Form Approved

OMB No. 0704-0188

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PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

1. REPORT DATE (DD-MM-YYYY)

March 2011

2. REPORT TYPE

Technical Report

3. DATES COVERED (From - To)

 

4. TITLE AND SUBTITLE

IEA Wind Task 26 - Multi-national Case Study of the Financial Cost 

of Wind Energy Work Package 1 Final Report

5a. CONTRACT NUMBER

DE-AC36-08GO28308

5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S)

P. Schwabe, M. Hand, and S. Lensink

5d. PROJECT NUMBER

NREL/TP-6A42-48155

5e. TASK NUMBER

WW3D1000

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory

1617 Cole Blvd.

Golden, CO 80401-3393

8. PERFORMING ORGANIZATION

REPORT NUMBER

NREL/TP-6A42-48155

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES) 10. SPONSOR/MONITOR'S ACRONYM(S)

NREL

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AGENCY REPORT NUMBER

12. DISTRIBUTION AVAILABILITY STATEMENT

National Technical Information Service

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13. SUPPLEMENTARY NOTES

14. ABSTRACT (Maximum 200 Words)

The lifetime cost of wind energy is comprised of a number of components including the investment cost, operation 

and maintenance costs, financing costs, and annual energy production. Accurate representation of these cost 

streams is critical in estimating a wind plant’s cost of energy. Some of these cost streams will vary over the life of a 

given project. From the outset of project development, investors in wind energy have relatively certain knowledge of 

the plant’s lifetime cost of wind energy. This is because a wind energy project’s installed costs and mean wind speed 

are known early on, and wind generation generally has low variable operation and maintenance costs, zero fuel cost, 

and no carbon emissions cost. Despite these inherent characteristics, there are wide variations in the cost of wind 

energy internationally, which is the focus of this report. Using a multinational case-study approach, this work seeks 

to understand the sources of wind energy cost differences among seven countries under International Energy 

Agency (IEA) Wind Task 26 – Cost of Wind Energy. The participating countries in this study include Denmark, 

Germany, the Netherlands, Spain, Sweden, Switzerland, and the United States. Due to data availability, onshore 

wind energy is the primary focus of this study, though a small sample of reported offshore cost data is also included. 

15. SUBJECT TERMS

wind energy; cost of wind energy; multi-national cost of wind energy; financial cost of wind energy

16. SECURITY CLASSIFICATION OF: 17. LIMITATION 

OF ABSTRACT

UL

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OF PAGES

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a. REPORT

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