A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

National Renewable Energy Laboratory 

Innovation for Our Energy Future 

Wind Turbine Design Cost 

and Scaling Model 

L. Fingersh, M. Hand, and A. Laxson 

Technical Report 

NREL/TP-500-40566 

December 2006 

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 
Wind Turbine Design Cost 

and Scaling Model 

L. Fingersh, M. Hand, and A. Laxson 

Prepared under Task No. WER6.0703 

Technical Report 

NREL/TP-500-40566 

December 2006 

National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov 

Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy 

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337
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Table of Contents 

Executive Summary ..................................................................................................................1 

1.0 Purpose of model .............................................................................................................1 

2.0 History..............................................................................................................................2 

3.0 Model Description.............................................................................................................4 

 3.1 Overview ...................................................................................................................4 

 3.2 COE ..........................................................................................................................4 

 3.3 Cost Summary...........................................................................................................7 

 3.4 Component Formulas ..............................................................................................10 

3.5 AEP.........................................................................................................................28 

4.0 Output Examples............................................................................................................34 

5.0 References.....................................................................................................................37 

List of Figures 

Figure 1. Blade Mass Scaling Relationship ............................................................................11 

Figure 2. Blade Cost Scaling Relationship (per blade) ...........................................................12 

Figure 3. Tower Mass Scaling Relationship ...........................................................................20 

List of Tables 

Table 1. GDP Escalation for All Categories Versus PPI for Selected Categories .....................7 

Table 2. Cost Estimate from Scaling Model: Land-Based, 1.5-MW Baseline Turbine.............35 

Table 3. Cost Estimate from Scaling Model: Offshore (Shallow-Water) 3-MW 

Baseline Turbine.......................................................................................................36

iii
Executive Summary 

The National Renewable Energy Laboratory’s (NREL) National Wind Technology Center has 

been working to develop a reliable tool for estimating the cost of wind-generated electricity, 

from both land-based and offshore wind turbines. This model is also intended to provide 

projections of the impact on cost from changes in economic indicators such as the Gross 

Domestic Product (GDP) and Producer Price Index (PPI). The model described has been built 

from work originally done by University of Sutherland under a United Kingdom Department of 

Trade and Industry Study and work performed for the U.S. Department of Energy (DOE) under 

its Wind Partnerships for Advanced Component Technology (WindPACT) projects. These 

models are intended to provide reliable cost projections for wind-generated electricity based on 

different scales (sizes) of turbines. They are not intended to predict turbine “pricing,” which is a 

function of volatile market factors beyond the scope of this work. The models in this study allow 

projections of both land-based and offshore technologies, though offshore technologies are still 

in their infancy and forecasts are extremely rough. These models also allow modeling of the cost 

impacts of certain advanced technologies that were studied under the WindPACT and Low Wind 

Speed Technology (LWST) projects. Cost estimates are projected based on turbine rating, rotor 

diameter, hub height, and other key turbine descriptors. Cost scaling functions have been 

developed for major components and subsystems. Wherever current industry information is 

available, the models have been cross checked or improved based on this industry information. 

Annual energy production has been estimated based on the Weibull probability distributions of 

wind, a standardized power curve, physical description of the turbine and physical constants and 

estimates from aerodynamic and engineering principles associated with aero and machine 

performance (efficiencies). The product of this work is a set of scaling functions and a tool that 

is capable of constant update and improvement as additional data are made available. As 

additional data become available and this model is updated it is expected that new versions of 

this description will be issued. 

1.0 Purpose of Model 

When evaluating any change to the design of a wind turbine, it is critical that the designer 

evaluate the impact of the design change on the system cost and performance. The designer 

must consider several elements of this process: initial capital cost (ICC), balance of station 

(BOS), operations and maintenance (O&M), levelized replacement cost (LRC), and annual 

energy production (AEP). As wind turbines grow more sophisticated and increase in size, the 

impact of design on these elements is not always clear. For example, increasing AEP may 

increase ICC. If one step does not balance out the other, proposed improvements may actually 

have a negative overall impact. 

The levelized COE has been used by DOE for some years to attempt to evaluate the total system 

impact of any change in design. This levelized COE is calculated using a simplified formula that 

attempts to limit the impact of financial factors, such as cost of money in wind farm 

development, so that the true impact of technical changes can be assessed. 

1
The constant pressure to grow wind turbines has also been a challenge for designers. It is often 

difficult to determine what the total impact of increasing the rating or rotor diameter of a turbine 

will be. Models that predict component cost and performance at a range of sizes or 

configurations have been a goal of the Federal Wind Energy Program for some years. Such 

models are invaluable to modelers and forecasters when attempting to project technology 

pathways. 

The work described in this document is an attempt to develop such a model, in a spreadsheet 

format, that can be used by designers to look at the impact of scaling and configuration on 

overall COE. 

A note of caution to the reader. Much of the data used to develop scaling functions for machines 

of greater than 1 to 2 MWs is based on conceptual designs. Many components are scaled using 

functions that are close to a cubic relationship. This is what would normally be expected for 

technologies that did not undergo design innovations as they grew in size. The WindPACT 

studies were not designed as optimization studies, but were structured to identify barriers to size 

increase. Once such barriers are clearly identified and evaluated, it is expected that designers 

will find innovative ways to get around them. This model should be viewed as a tool to help 

identify such barriers and quantify the cost and mass impact of design changes on components 

without such innovation. With expansion it can then be used to help designers to quantify the net 

value of an improvement of any component. The importance of this should not be lost on those 

that use these models. It would be difficult for a user to exercise these models in an optimization 

mode without taking into account the innovation that could be applied to the design of many of 

the major components to reduce the size, mass and cost as they increase in rating. 

2.0 History 

There have been several attempts to develop modern scaling models. But because wind turbines 

have changed in size and configuration so rapidly, many models are out of date before they can 

be used effectively by designers. In the mid to late 1990s, the configuration for utility-scale 

turbines began to stabilize around the three-bladed, upwind design. During this same period, an 

effort at the University of Sunderland resulted in a set of scaling tools for the machines of the 

period [1]. This report contained valuable models to predict the impact of machine size on 

turbine components. But within a few years of the publication, machine size had increased by a 

factor of 2 to 4 in some cases, and several new technology approaches began to be incorporated. 

Beginning in 1999, DOE began its WindPACT projects. These projects were focused on 

determining the potential technology pathways that would lead to more cost-effective wind 

turbine design. One of the elements and goals of this work was to determine the impact of 

increased machine size and machine configuration on total COE. This was done by completing 

several major studies. In each study, the team completed conceptual designs of turbines and 

wind systems at a range of sizes, from 750 kW to 5 MW. Wherever possible, these studies 

developed scaling relationships for subsystems, components, or cost elements across the range of 

sizes. This work culminated in seven principal studies: 

• Composite Blades for 80- to 120-m Rotors [2] 

• Turbine, Rotor and Blade Logistics [3] 

2
• Self Erecting Tower and Nacelle Feasibility [4] 

• Balance of Station Cost [5] 

• Turbine Rotor Design Study [6] 

• Drive Train Alternative Design Studies [7] [8] 

The scaling relationships developed during these studies also evaluated the relationships 

developed in the earlier Sunderland model for use or guidance. Where superior information was 

developed during the study efforts, the Sunderland model was abandoned and new relationships 

were defined. 

In addition to looking at scaling issues, the turbine rotor design study [6] developed structural 

models for more than 20 different turbine rotor and tower configurations and determined the 

structural and cost impact of these different design configurations. This rotor design study 

summarizes the scaling results up to the time of its completion in June 2002. The two alternative 

drivetrain design studies extended this work for drivetrains by each exploring a number of 

alternative drivetrain (gear box, generator, power converter) configurations at different machine 

sizes, and the total impact of these configurations on total COE. 

In 2002, the DOE Wind Energy Program began supporting LWST projects. These industry 

partnerships extended the work of WindPACT by beginning the development of actual turbine 

components and prototypes that would be expected to lower the COE for utility-scale wind 

turbines. Several of these projects have been completed, and a number of them are still under 

way and provide greater insight into the actual cost of systems and components in the large 

machines. Though much of the data from these studies are confidential, the aggregate results can 

be used to provide valuable additional data points and cross checks for scaling relationships. 

The baseline turbines in all of these studies was a three bladed upwind turbine modeled after the 

Zond/Enron/GE machines that evolved into the GE 1.5 MW machine. They are assumed to be 

grid-connected, full span pitch controlled, variable speed turbines with active yaw and steel 

tubular towers. However, the data for cost and mass of components in each of these studies were 

derived independently of any Zond/Enron/GE data. Costs were based on a 50 MW wind farm 

composed of machines of mature production installed in the upper Midwest. All cost 

calculations were based on a low wind speed site with an annual average wind velocity of 5.8 

meters per second with a wind shear of 1/7. A more detailed description of turbines in each 

study can be found in the beginning of the study reports identified in the Appendix. 

Beginning in late 2005, researchers at NREL’s National Wind Technology Center began 

developing a spreadsheet model of these scaling relationships to assist in projecting future wind 

turbine costs. The purpose of this work was two-fold. First, it was to provide a traceable process 

for projecting turbine cost and size impacts for the Government Performance and Results Act 

(GPRA). This was to be accomplished by providing detailed reproducible cost models for use in 

the National Energy Modeling System (NEMS) runs. The second purpose of this work was to 

provide a baseline tool for evaluating the impact of machine design and growth on cost for 

proposed offshore wind turbine systems. 

3
To prepare this spreadsheet model, the WindPACT rotor study was used as a primary scaling 

formula source. In the process of computerizing these formulas and comparing them to current 

technology, a number of deviations were noted between this 2002 model and current trends. 

Data for these comparisons came from several sources and will be discussed in more detail later 

in this report. The result was a set of models that could be used to project the total COE for a 

wind turbine over a range of sizes and configurations. This model is not intended as an end 

result in itself, but as a starting point for a continually growing and improving tool that 

constantly incorporates new data as the technology grows and improves. 

3.0 Model Description 

3.1 Overview 

The DOE/NREL scaling model is a spreadsheet-based tool that uses simple scaling relationships 

to project the cost of wind turbine components and subsystems for different sizes and 

configurations of components. The model does not handle all potential wind turbine 

configurations, but rather focuses on those configurations that are most common in the 

commercial industry at the time of writing. This configuration focuses on the three-bladed, 

upwind, pitch-controlled, variable-speed wind turbine and its variants. It is believed that this 

configuration will dominate wind energy for some extended period, and the model can best be 

maintained using data for these designs as they become available. The model is not intended to 

be a stagnant, final product, but rather a constantly evolving tool that can be refined as new data 

become available. 

Formulas in the model, in its early versions, are quite simple. In most cases, cost and mass 

models are a direct function of rotor diameter, machine rating, tower height, or some 

combination of these factors. In cases where better definition is available, more sophisticated 

approaches are used or are under development. These will be discussed in each component 

section below. The results of each model are assumed to be in 2002 dollars. This has been done 

for purposes of consistency. Where cost data was available from different years, it was 

converted to 2002 dollars before the cost and scaling factors were developed. Cost data is based 

on a mature design and a 50 MW wind farm installation, with mature component production. 

3.2 COE 

Though the model produces component cost and mass figures where they can be supported, its 

primary output is levelized COE. 

3.2.1 Cost of Energy 

COE is calculated using the following equation: 

 COE = (FCR x ICC) + AOE 

 AEPnet

4
where COE ≡ levelized cost of energy ($/kWh) (constant $) 

FCR ≡ fixed charge rate (constant $) (1/yr) 

ICC ≡ initial capital cost ($) 

AEPnet ≡ net annual energy production (kWh/yr) 

 AOE ≡ annual operating expenses 

 ≡ LLC+ (O&M + LRC) 

 AEPnet 

 LLC ≡ land lease cost 

 O&M ≡ levelized O&M cost 

 LRC ≡ levelized replacement/overhaul cost 

3.2.2 Fixed Charge Rate 

The fixed charge rate (FCR) is the annual amount per dollar of initial capital cost needed to 

cover the capital cost, a return on debt and equity, and various other fixed charges. This rate is 

imputed from a hypothetical project, modeled using a pro forma cash flow spreadsheet model. 

For the current base model, FCR includes construction financing, financing fees, return on debt 

and equity, depreciation, income tax, and property tax and insurance, and is set to 0.1158 per 

year. In future improvements to the model, alternative financial options will be provided. The 

10-year Section 45 Renewable Energy Production Tax Credit is not included in the FCR, nor is it 

considered in any of the models. 

3.2.3 Initial Capital Cost 

The initial capital cost is the sum of the turbine system cost and the balance of station cost. 

Neither cost includes construction financing or financing fees, because these are calculated and 

added separately through the fixed charge rate. The costs also do not include a debt service 

reserve fund, which is assumed to be zero for balance sheet financing. 

Primary cost elements tracked in the model include the following: 

• Rotor 

o Blades 

o Hub 

o Pitch mechanisms and bearings 

o Spinner, nose cone 

• Drive train, nacelle 

o Low-speed shaft 

o Bearings 

o Gearbox 

o Mechanical brake, high-speed coupling, and associated components 

o Generator 

o Variable-speed electronics 

o Yaw drive and bearing 

o Main frame 

5
o Electrical connections 

o Hydraulic and cooling systems 

o Nacelle cover 

• Control, safety system, and condition monitoring 

• Tower 

• Balance of station 

o Foundation/support structure 

o Transportation 

o Roads, civil work 

o Assembly and installation 

o Electrical interface/connections 

o Engineering permits 

When evaluating offshore turbines, the following additional components or elements are 

considered: 

• Marinization (added cost to handle marine environments) 

• Port and staging equipment 

• Personal access equipment 

• Scour protection 

• Surety bond (to cover decommissioning) 

• Offshore warranty premium 

3.2.4 Annual Operating Expenses 

Land Lease Cost/Bottom Lease Cost 

Annual operating expenses (AOE) include land or ocean bottom lease cost, levelized O&M cost, 

and levelized replacement/overhaul cost (LRC). Land lease costs (LLC) are the rental or lease 

fees charged for the turbine installation. LLC is expressed in units of $/kWh. 

Levelized O&M Cost 

A component of AOE that is larger than the LLC is O&M cost. O&M is expressed in units of 

$/kWh. The O&M cost normally includes 

• labor, parts, and supplies for scheduled turbine maintenance 

• labor, parts, and supplies for unscheduled turbine maintenance 

• parts and supplies for equipment and facilities maintenance 

• labor for administration and support. 

Levelized Replacement/Overhaul Cost 

LRC distributes the cost of major replacements and overhauls over the life of the wind turbine 

and is expressed in $/kW machine rating. 

6
3.2.5 Net Annual Energy Production 

The net AEP is a calculation of the projected energy output of the turbine based on a given 

annual average wind speed. The gross AEP is adjusted for factors such as rotor coefficient of 

power, mechanical and electrical conversion losses, blade soiling losses, array losses, and 

machine availability. The model used for calculating AEP is described in greater detail in 

section 3.5. 

3.3 Cost Summary 

Costs used to develop scaling curves in these models are based on 2002 dollars. Where data 

from other periods have been incorporated into the data for evaluating the scaling curves, they 

have been deescalated using the Producer Price Indexes (PPIs) described below. 

In 2004 and 2005, rapid changes in the cost of such key materials as structural steel and copper 

highlighted the impact that individual material costs have on major wind turbine components. 

To compensate for such fluctuations and to accurately project the cost of components into out 

years, a component cost escalation model was developed based on the PPI. The PPI maintained 

by the U.S. Department of Labor, Bureau of Labor Statistics, tracks costs of products and 

materials over a broad range of industries. They are sorted by North American Industry 

Classification System (NAICS) codes that provide a rational grouping of U.S. industries and 

products. The PPI was scoured for categories comparable to wind turbine components. In some 

instances, a wind turbine component is represented by a composite of several PPI categories. 

Labor-intensive components such as rotor blades and electrical interface components include a 

labor cost escalator, which was specified as the general inflation index, based on the Gross 

Domestic Product (GDP). Other components, such as the hub, are delivered in an essentially 

finished state so it was assumed that labor costs were included in the appropriate PPI category. 

While this approach allows the escalation of costs from the 2002 baseline date to the present, it 

does not allow for projections into the future. 

Table 1 provides an example of the differences that would be seen in using PPIs for selected 

categories versus using the GDP for all categories. The TC Baseline is the wind energy technical 

characterization work being completed by NREL for DOE. 

Table 1. GDP Escalation for All Categories Versus PPI for Selected Categories. 

2002 baseline 

costs 

2005 – PPI 

component 

escalation 

2005 – GDP 

general 

inflation 

escalation 

LWST, $/kW installed 981 1135 1079 

LWST, $/kWh at 5.8 m/s 0.0480 0.0551 0.0528 

TC Baseline, $/kW installed 1049 1225 1153 

TC Baseline, $/kWh at 5.8 m/s 0.0433 0.0501 0.0476 

7
The PPI categories and the associated NAICS codes are detailed below for each wind turbine 

component listed in the baseline cost estimate. These are provided to indicate to the reader 

which PPI categories are used in this model to develop commodity inflation factors. The 

percentages expressed here are the percentages of each commodity assumed to make up the final 

product, not percentage increase in cost. 

• Baseline blade material cost 

o Fiberglass fabric (NAICS Code 3272123) = 60% 

o Vinyl type adhesives (NAICS Code 32552044) = 23% 

o Other externally threaded metal fasteners, including studs (NAICS Code 

332722489) = 8% 

o Urethane and other foam products (NAICS Code 326150P) = 9% 

• Advanced blade material 

o Fiberglass fabric (NAICS Code 3272123) = 61% 

o Vinyl type adhesives (NAICS Code 32552044) = 27% 

o Other externally threaded metal fasteners, including studs (NAICS Code 

332722489) = 3% 

o Urethane and other foam products (NAICS Code 326150P) = 9% 

• Blade assembly labor cost 

o General inflation index 

• Hub 

o Ductile iron castings (NAICS Code 3315113) 

• Pitch mechanisms and bearings 

o Bearings (NAICS Code 332991P) = 50% 

o Drive motors (NAICS Code 3353123) = 20% 

o Speed reducer, i.e., gearing (NAICS Code 333612P) = 20% 

o Controller and drive - industrial process control (NAICS Code 334513) = 10% 

• Low-speed shaft 

o Cast carbon steel castings (NAICS Code 3315131) 

• Bearings 

o Bearings (NAICS Code 332991P) 

• Gearbox 

o Industrial high-speed drive and gear (NAICS Code 333612P) 

• Mechanical brake, high-speed coupling, etc. 

o Motor vehicle brake parts and assemblies (NAICS Code 3363401) 

• Generator (not permanent-magnet generator) 

o Motor and generator manufacturing (NAICS Code 335312P) 

• Variable-speed electronics 

o Relay and industrial control manufacturing (NAICS Code 335314P) 

• Yaw drive and bearing 

o Drive motors (NAICS Code 3353123) = 50% 

o Ball and roller bearings (NAICS Code 332991P) = 50% 

• Main frame 

o Ductile iron castings (NAICS Code 3315113) 

8
• Electrical connections 

o Switchgear and apparatus (NAICS Code 335313P) = 25% 

o Power wire and cable (NAICS Code 3359291) = 60% 

o Assembly labor (general inflation index) = 15% 

• Hydraulic system 

o Fluid power cylinder and actuators (NAICS Code 339954) 

• Nacelle cover 

o Fiberglass fabric (NAICS Code 3272123) = 55% 

o Vinyl type adhesives (NAICS Code 32552044) = 30% 

o Assembly labor (general inflation index) = 15% 

• Control, safety system 

o Controller and drive - industrial process control (NAICS Code 334513) 

• Tower 

o Rolled steel shape manufacturing - primary products (NAICS Code 331221) 

• Foundations 

o Other heavy construction (NAICS Code BHVY) 

• Transportation 

o General freight trucking, long-distance, truckload (NAICS Code 335312P) 

• Roads, civil works 

o Highway and street construction (NAICS Code BHWY) 

• Assembly and installation 

o Other heavy construction (NAICS Code BHVY) 

• Electrical interface and connections (cost established based on transformer at 40%) 

o Power and distribution transformers (NAICS Code 3353119) = 40% 

o Switchgear and apparatus (NAICS Code 335313P) = 15% 

o Power wire and cable (NAICS Code 3359291) = 35% 

o Assembly labor (general inflation index) = 10% 

• Permits, engineering 

o General inflation index 

• Levelized replacement 

o General inflation index 

• Operations and maintenance 

o General inflation index 

• Land lease 

o General inflation index 

Specific offshore categories include the following: 

• Marinization 

o General inflation index 

• Offshore warranty premium 

o General inflation index 

• Monopole foundation (pile driven tower) 

o Other heavy construction (NAICS Code BHVY) 

• Offshore port and staging equipment 

o Other heavy construction (NAICS Code BHVY) 

9
• Offshore site preparation (scour protection) 

o Other heavy construction (NAICS Code BHVY) 

• Offshore LRC 

o General inflation index 

• Offshore O&M 

o General inflation index 

• Offshore personnel access equipment 

o General inflation index 

The actual commodity cost factors are developed by extracting PPI codes from the Bureau of 

Labor Statistics data bases for the PPIs for the range of dates of interest. As the baseline costs 

models are primarily based on September 2002, comparing the September 2002 index for each 

category with the index for a later month and year will provide the user with the proper 

escalation factor. This PPI data can be found at http://www.bls.gov/ppi/. The PPI numbers are 

updated monthly and allow adjustments to cost on a monthly basis for comparison. Using this 

method, it is only possible to project cost from 2002 to the present. The model does not provide 

for any attempt at projecting commodity costs into the future. The General Inflation index 

identified here is based on the Gross Domestic Product. The GDP numbers are updated yearly. 

As additional information is obtained, these breakdowns and NAICS assignments may be 

adjusted. 

3.4 Component Formulas 

Notice: Unless otherwise noted, all dimensions are in meters and all masses are in kilograms. 

The outputs of all formulas will be in 2002 dollars, unless otherwise noted. An escalation can 

then be applied using the PPIs or GDP, as earlier described. 

3.4.1 Land Based 

3.4.1.1 Blades 

Blade Mass - The blade mass relationships were developed using WindPACT scaling study 

designs [2, 6]. The WindPACT static load design was also used by TPI Composites in their 

blade cost scaling study [10]. The static load design used International Electrotechnical 

Commission (IEC) Class I wind conditions, while the WindPACT baseline designs used IEC 

Class II wind conditions. Industry data compare well with the WindPACT baseline mass scaling 

relationship. It appears that typical, 2002 technology blades follow the WindPACT baseline 

design. LM Glasfiber has a new line of blades that take advantage of a lower-weight root design 

(http://www.lmglasfiber.com/Products/Wing%20Overview/2000-5000.aspx). Carbon is 

included in the 61.5-m blade, but apparently it is not included in the other two, lower-weight 

blades. TPI performed an innovative blade design study that used several technology 

improvements to reduce blade weight. These designs were based on an IEC Class III wind 

condition, and the resulting weight is slightly lower than the commercially available LM blade of 

comparable length. The TPI study produced two blade designs using flat back airfoils: one was 

all fiberglass and the other included a carbon fiber spar. The study also developed two root 

designs: one used 120 studs and the other used 60 T-bolts. The four permutations of blade shell 

10
and root design result in blades of similar mass and cost. The use of carbon has not been isolated 

from other blade improvements, such as root design and airfoil selection. At this time, only one 

"advanced" blade curve seems appropriate, and this curve represents combinations of technology 

enhancements that may or may not include carbon. However, at some blade length, these 

improvements must include carbon to provide the necessary stiffness to avoid extreme blade 

deflection. This length is not yet identified. Also, the advanced blade technology should not be 

used for rotors less than 100 m in diameter. The baseline blade mass relationship was selected to 

follow the WindPACT baseline design curve; the advanced blade mass relationship was selected 

to follow the LM Glasfiber design curve. The WindPACT final designs from the rotor study [6] 

indicate that even greater mass reduction as a function of blade length is achievable. Figure 1 

shows the results of each of these studies. 

WindPACT Baseline Design:

y = 0.1452x2.9158

WindPACT Static Load Design:

y = 0.2113x2.8833

WindPACT Final Design:

y = 0.1527x2.6921

LM Glasfiber Blade Design:

y = 0.4948x2.53

0

5000

10000

15000

20000

25000

30000

35000

0 10 20 30 40 50 60 70

Rotor Radius (m)

Total Mass (kg)

WindPACT - Static load design

TPI - baseline design

WindPACT - Baseline design

WindPACT - Final design

LM Glasfiber Blades

WindPACT - Commercial Data

TPI Innovative Concept Blades

Baseline blade mass curve = WindPACT baseline

Advanced blade mass curve = LM advanced design

Figure 1. Blade mass scaling relationship. 

Baseline: mass = 0.1452 * R2.9158 per blade 

Advanced: mass = 0.4948 * R2.53 per blade 

where R = rotor radius 

11
Blade Cost - The blade costs were developed using the TPI blade cost scaling report [10]. This 

study investigated the scaling effects of materials, labor, profit & overhead, other costs such as 

tooling, and transportation. Because this cost model does not include transportation of the blades 

in the turbine capital cost, the transportation portion of blade cost estimated by TPI was 

excluded. It was assumed that the profit, overhead, and other costs were a percentage of the 

material and labor costs. On average, this amounted to 28% over all blade lengths studied. The 

blade cost was then computed as the sum of the material costs and labor costs, divided by 

(1 - 0.28) such that the other costs were maintained at 28% of the total blade cost. It was 

assumed that the labor costs would scale the same for the baseline blade and for the advanced 

blade. Two cost curves were created for the blade materials, representing the baseline design and 

the advanced design. A linear relationship between cost and R3 was developed for the blade 

material cost to minimize deviation in the total blade cost curve fit. It was assumed that the 

advanced blade cost would scale with the baseline cost. Although the mass curves scale 

differently between the baseline and advanced blades, this simplifying assumption was made 

because the baseline cost did not scale exactly the same as the mass. The cost estimate for the 

advanced blade consists of the average of the four cost estimates for the four different blade 

designs from the TPI innovative study. Because we lacked cost data for the advanced blade 

designs, the scaling was assumed to follow the baseline blade material cost. Note that the 

advanced blade cost is not in any way related to the advanced blade mass based on LM Glasfiber 

These cost scaling relationships are shown in Figure 2 with the WindPACT rotor study cost for 

Figure 2. B

comparison. 

lade cost scaling relationship (per blade). 

Advanced Material Cost:

2002$ = 0.04019R^3 - 21051

TPI Labor Costs:

2002$ = 2.7445R2.5025

WindPACT Blade Cost:

2002$ = 3.1225R2.879

Baseline Material Cost:

2002$ = 0.4019R^3 - 955.24

$-

$50,000

$100,000

$150,000

$200,000

$250,000

$300,000

$350,000

$400,000

0 10 20 30 40 50 60 70 8

Rotor Radius (m)

Cost ($)

0

TPI total blade cost

TPI labor cost

TPI baseline blade material cost

TPI advanced blade material cost

WindPACT blade cost 2002 $

Power (baseline total blade cost curve)

Power (advanced total blade cost curve)

Total Blade Cost:

$ = (Material + Labor) / (1-0.28)

12
Cost = (material cost + labor cost)/(1 - 0.28) 

E + 2.7445 * R2.5025GDPE]/(1 - 0.28) per blade 

ost Escalation Methodology - In the TPI cost scaling study [10], the blade material 

on was 

rs. 

terial 

the 

 on 

.4.1.2 Hub 

evelopment of a scaling formula for hubs began with the WindPACT rotor design study [6]. 

ub mass = 0.954 * (blade mass/single blade) + 5680.3 

ub cost = hub mass * 4.25 [6] 

.4.1.3 Pitch Mechanisms and Bearings 

he pitch mechanisms model began with the WindPACT rotor design study data and were 

ss 

otal Pitch Bearing Mass = .1295*total blade mass(three blades) +491.31 

ost of the pitch bearings was estimated as a function of the rotor diameter. The pitch housing 

otal pitch system cost (three blades) 

Baseline: cost = [(0.4019 * R3 – 955.24) * BC

Advanced: cost = [(0.4019 * R3 – 21051) * BCE + 2.7445 * R2.5025GDPE]/(1 - 0.28) per blade

where R = rotor radius, BCE = blade material cost escalator, GDPE = labor cost escalator 

C

components were presented for the three blade lengths studied. The average compositi

determined and grouped into fiberglass, resin & adhesive, core, and studs corresponding to 

NAICS industry codes. The TPI innovative blade design study [11] used costs in 2003 dolla

The blade composition was also presented for the four advanced blade designs, but for the 

escalation methodology only the two fiberglass blades were examined. Using the blade ma

composition and the four NAICS codes, the blade costs were deescalated to 2002 dollars to 

determine the blade material cost scaling relationship. The cost model output, which allows 

user to specify the output dollar year, is computed using the formula above. The blade material 

cost is escalated based on the four primary components: fiberglass, resin & adhesive, core, and 

studs. The baseline blade is assumed to be composed of 60% fiberglass, 23% vinyl adhesive, 8 

% studs, and 9% core material. The advanced blade is composed of 61% fiberglass, 27% vinyl 

adhesive, 3% studs, and 9% core material. In the equations above, the labor cost is escalated 

with the GDP, and the blade material cost is escalated with the composite escalator depending

the technology. 

3

D

These data were further augmented by data from industry Web sites and LWST project reports. 

A revised scaling curve was developed using hub mass as a function of a single blade mass. The 

revised formula is: 

H

H

3

T

augmented with other available industry data and data from LWST reports. The bearing ma

was calculated as a function of the blade mass for all three blades. Actuators and drives were 

estimated as 32.8% of the bearing mass + 555 kg. 

T

Total Pitch System Mass = (Total Pitch Bearing Mass * 1.328) + 555 

C

and actuator cost was estimated as 128% of the bearing cost. 

T

13
 = 2.28 * (.2106*Rotor Diameter 2.6578) 

.4.1.4 Spinner, Nose Cone 

he spinner (nose cone) was not calculated independently in the WindPACT rotor study, so a 

ose cone mass = 18.5 * rotor diameter – 520.5 

ose cone cost = nose cone mass * 5.57 

.4.1.5 Low-Speed Shaft

ow-speed shaft mass and cost were derived based on rotor diameter. All data were taken from 

ow-speed shaft mass = 0.0142 * rotor diameter 2.888

ow-speed shaft cost = 0.01 * rotor diameter 2.887

.4.1.6 Main Bearings 

he WindPACT main bearing mass and cost as reported on page 19 of the original WindPACT 

n of 

earing mass = (rotor diameter * 8/600 - 0.033) * 0.0092 * rotor diameter 2.5

he bearing housing mass was assumed to be equal to the bearing mass. 

otal bearing system cost = 2 * bearing mass * 17.6 [6] 

.4.1.7 Gearbox 

earboxes and generators are perhaps the most complicated components to predict a mass and 

 

n for 

3

T

new formula was derived, primarily from data in WindPACT drivetrain and LWST reports, 

augmented with data from the Advanced Research Turbine at the National Wind Technology

Center. 

N

N

3

L

the WindPACT rotor study. Several alternative drive train designs do not use independent lowspeed shafts, so no low-speed shaft data are calculated in developing cost and mass data for 

direct drive, single-stage drive, or multi-generator drives. 

L

L

3

T

rotor design study report was stated incorrectly. This was corrected and reissued in April of 

2006. The formula as stated in the revised report was used for this calculation. It is a functio

the rotor diameter. 

B 

T

T

3

G

cost for. There are a range of designs and a myriad of ways in which to configure them. This 

work assumes four basic designs, all studied in detail in the two WindPACT drivetrain studies.

The four designs covered in this model include a three-stage planetary/helical gearbox with highspeed generator, single-stage drive with medium-speed generator, a multi-path drive with 

multiple generators, and a direct drive with no gearbox. The primary source for informatio

the three-stage planetary/helical is the WindPACT rotor study, with costs adjusted from 

14
additional information in the two WindPACT advanced drivetrain studies [7, 8]. Data fo

remaining three design types come primarily from the drivetrain studies and are adjusted for da

from industry and LWST reports, where available. The mass for gearboxes is scaled based on 

the low-speed shaft torque and thus adjusts for differences in rotor diameter and tip speed. The

cost is a function of machine rating in kW. 

r the 

ta 

hree-Stage Planetary/Helical 

ass = 70.94 * low-speed shaft torque 0.759

otal Cost = 16.45* machine rating 1.249

ingle-Stage Drive with Medium-Speed Generator 

ass = 88.29 * low-speed shaft torque 

otal Cost = 74.1 * machine rating 1.00 

ulti-Path Drive with Multiple Generators 

ass = 139.69 * low-speed shaft torque 

otal Cost = 15.26 * machine rating 1.249

irect Drive 

he direct-drive approach has no gearbox. 

.4.1.8 Mechanical Brake, High-Speed Coupling, and Associated Components 

rake cost is estimated as a function of machine rating. This was developed from the 

ss is back 

rake/coupling cost = 1.9894 * machine rating - 0.1141 

rake/coupling mass = (brake coupling cost/10) 

.4.1.9 Generator 

here are a wide range of possible generator designs. For this model, these designs are limited 

ta 

T

M

T

S

0.774 M

T

M

0.774 M

T

D

T

3

B

WindPACT rotor study cost data, converted to a function based on machine rating. Ma

calculated based on $10/kg [8]. 

B

B

3

T

to high-speed wound rotor designs used with high-speed gearboxes, and permanent-magnet 

generators used with single-stage gearboxes, multi-generator gearboxes, and direct drive. Da

for these designs were extracted primarily from the WindPACT rotor study and the two 

WindPACT drivetrain studies. These data were cross-checked with other data where available, 

15
such as the Controls Advanced Research Turbine at the National Wind Technology Center. 

Generator mass calculations for high-speed wound rotor, medium-speed permanent-magnet, a

multi-generator designs were based on machine power rating in kW. They were each assumed to

follow the same power law curve. The direct-drive mass was based on low-speed shaft torque. 

All cost data are a direct function of machine rating. 

nd 

hree-Stage Drive with High-Speed Generator 

ass = 6.47 * machine rating 

otal Cost = machine rating * 65 

ingle-Stage Drive with Medium-Speed, Permanent-Magnet Generator 

ass = 10.51 * machine rating 

otal Cost = machine rating * 54.73 

ulti-Path Drive with Permanent-Magnet Generator 

ass = 5.34 * machine rating 

otal Cost = machine rating * 48.03 

irect Drive 

ass = 661.25 * low-speed shaft torque 0.606

otal Cost = machine rating * 219.33 

.4.1.10 Variable-Speed Electronics 

ll designs in this model are assumed to have a power converter capable of handling full power 

otal Cost = machine rating * 79 [7] 

T

0.9223 M

T

S

0.9223 M

T

M

0.9223 M

T

D

M

T

3

A

output. This allows both variable-speed operation as well as “low-voltage ride through” when 

properly programmed. All converters are calculated as a function of rated machine power. A 

number of alternative approaches to power converters are possible, but they require additional 

study and modeling before incorporation into this tool. Mass for this component is not 

calculated, though in some designs a portion or all of the converter could be in the nacelle 

impacting structural and dynamics design issues. 

T

16
3.4.1.11 Yaw Drive and Bearing 

Yaw bearing costs were calculated using the original formula developed in the WindPACT rotor 

study; these were based on quotes from Avon Bearing. These calculations were sized on rotor 

diameter. Total yaw system cost is twice the bearing cost. Mass data in the WindPACT study 

were based on calculated moments. These moments were calculated using a structural dynamics 

program such as Fatigue, Aerodynamics, Structures, and Turbulence (FAST) or Automated 

Dynamic Analysis of Mechanical Systems (ADAMS). However, since the design and cost 

scaling model does not have these moments available to it, the yaw bearing mass was calculated 

as a function of rotor diameter, taken from the data supplied in the WindPACT rotor study. The 

bearing housing was estimated as 60% of the bearing mass. 

Total yaw system mass = 1.6 * (0.0009 * rotor diameter 3.314) 

Total Cost = 2 * (0.0339 * rotor diameter 2.964) 

3.4.1.12 Mainframe 

The mainframe cost is calculated as a function of rotor diameter. Platforms and railing are 

calculated on $/kg. Data for these relationships were extracted primarily from the WindPACT 

rotor study and the two WindPACT drivetrain reports. Minor adjustments were made where 

other industry or LWST data were available. Mainframe mass and cost are functions of the type 

of drive train. Each drive train design distributes its load in a different manner and will have a 

different length. Mass and cost for the mainframe are calculated as a function of the rotor 

diameter. The mass functions for all three designs were assumed to follow the same power law 

function, which is slightly less than a square relationship. It is assumed that designers find more 

creative ways to handle the loads as size increases keeping this from following a cubic 

relationship as might seem intuitive. Additional mass of 12.5% is added for platforms and 

railing. Costs for the additional platforms and railing are calculated on a $/kg basis. 

 

Three-Stage Drive with High-Speed Generator 

Mainframe mass = 2.233 * rotor diameter 1.953

Mainframe cost = 9.489 * rotor diameter 1.953

Single-Stage Drive with Medium-Speed, Permanent-Magnet Generator 

Mainframe mass = 1.295 * rotor diameter 1.953

Mainframe cost = 303.96 * rotor diameter 1.067

17
Multi-Path Drive with Permanent-Magnet Generator 

Mainframe mass = 1.721 * rotor diameter 1.953

Mainframe cost = 17.92 * rotor diameter 1.672

Direct Drive 

Mainframe mass = 1.228 * rotor diameter 1.953

Mainframe cost = 627.28 * rotor diameter 0.85

Platforms and Railings 

Platform and railing mass = 0.125 * mainframe mass 

Platform and railing cost = mass * 8.7 

3.4.1.13 Electrical Connections 

Electrical connections, including switchgear and any tower wiring, were taken from the 

WindPACT rotor study and are calculated as $40/kW of machine rating. No adjustment was 

made to these data. 

Electrical connection cost = machine rating * 40 [6] 

3.4.1.14 Hydraulic and Cooling Systems 

Hydraulic and cooling system estimates were taken from LWST reports. Mass is a function of 

machine rating in kW. Cost is a function of machine rating times $/kW. 

Hydraulic, cooling system mass = 0.08 * machine rating 

Hydraulic, cooling system cost = machine rating * 12 

3.4.1.15 Nacelle Cover 

Nacelle cover costs were derived from WindPACT rotor study data combined with WindPACT 

drive-train study and LWST report data. A single function was derived for all drivetrain 

configurations, as data were too scarce to develop individual formulas for different drivetrain 

configurations. The calculations are a function of machine rating in kW. Nacelle cover mass 

was derived from Nacelle cover cost. The cost per kg for the nacelle cover was taken from the 

WindPACT rotor study. 

18
Nacelle cost = 11.537 * machine rating + 3849.7 

Nacelle mass = nacelle cost / 10 [6] 

3.4.1.16 Control, Safety System, Condition Monitoring 

WindPACT studies identified a cost of $10,000 for control, safety, and condition monitoring 

systems for a 750-kW turbine. A slight scaling factor was applied for larger machines to take 

into account additional wiring and sensors. However, these data were based on 1999 designs. 

During the early 2000s, operators realized the value of additional sensing and monitoring 

systems. To take this into account, this number for land-based systems was increased to $35,000 

in 2002 dollars, regardless of machine size or rating. Offshore systems are expected to be more 

sophisticated and extensive. For offshore systems, this number was raised to $55,000, regardless 

of machine size or rating. These rough estimates were based on discussions with industry 

development partners. 

3.4.1.17 Tower 

The tower mass and cost scaling relationships were based primarily on the WindPACT studies 

[3, 6]. All towers discussed here are steel tubular towers. The tower mass is scaled with the 

product of the swept area and hub height, as shown in Figure 3. Given any turbine diameter, hub 

height, and tower mass, a comparison can be made between steel tubular towers. The initial 

WindPACT scaling studies provide a crude estimate of tower mass based on the most extreme 

base moment. Turbines are designed for trade-offs between buckling and overturning moment 

for a more precise set of load conditions. Fatigue loads are also estimated. The WindPACT 

rotor study baseline design [6] uses conventional technology circa 2002 and scales it up. The 

WindPACT rotor study final design [6] uses advanced technologies including tower feedback in 

the control system, flap-twist coupling in the blade, and reduced blade solidity in conjunction 

with higher tip speeds. These final designs show the trends for future design. 

Commercial turbines were compared with these WindPACT scaling relationships. This 

comparison assumes that the different rotors have similar thrust coefficients. The tower mass, 

provided by the manufacturers, is based on a design for the variety of design conditions and 

tradeoffs for turbines with different rotors and hub heights. The WindPACT rotor study baseline 

design scaling relationship represents most commercial turbines today, but it may be somewhat 

conservative. The WindPACT rotor study final design scaling relationship may be achievable 

through technology innovation, but it results in mass projections much lower than what is 

commercially available today. The impact of towers with base diameters of greater than 4.3 

meters is generally reflected in the transportation and erection costs, but these functions should 

be used carefully when looking at towers of much greater than 80 meters, as design tradeoff for 

transportation and erection will have a major impact on design.

19
WindPACT Baseline design:

y = 0.3973x - 1414.4

R2

 = 0.9998

WindPACT Final design:

y = 0.2694x + 1779.3

R2

 = 0.9977

WindPACT Static load design:

y = 0.4649x + 324.33

R2

 = 1

0

50000

100000

150000

200000

250000

300000

350000

400000

450000

500000

0 200000 400000 600000 800000 1000000 1200000

Swept area * height (m^3)

Total mass (kg)

WindPACT - Static load design

WindPACT - Baseline design

WindPACT - Final design

Commercial Turbines in 2005

Additional turbines from WindPACT

Figure 3. Tower mass scaling relationship. 

Baseline: mass = 0.3973 * swept area * hub height – 1414 

Advanced: mass = 0.2694 * swept area * hub height + 1779 

WindPACT cost of steel was $1.50/kg in 2002 dollars. The tower cost is computed as follows: 

Total Cost = mass * 1.50 

The cost is then escalated using the PPI to the appropriate year dollars. 

3.4.1.18 Foundation 

Foundation estimates are based solely on the WindPACT rotor study report. Foundations used to 

develop these estimates were primarily based on a design by Patrick and Henderson that can 

generally be described as a hollow drilled pier. These foundations are approximately the 

diameter of the tower base and may be 30 or more feet in depth. A number of alternate 

foundation designs are possible that will vary based on local soil conditions. No attempt has 

been made here to try to evaluate different design approaches. Foundations were scaled as a 

function of hub height times rotor swept area, which is directly proportional to the tower 

overturning moment. No mass data were calculated for the foundation. 

Foundation cost = 303.24 * (hub height * rotor swept area) 0.4037 

20
3.4.1.19 Transportation 

The transportation estimate was taken from the WindPACT logistics study [3] and is a function 

of machine rating. These costs reflect the large cost increases required for 3- and 5-MW turbines 

if transported and erected onshore. 

Transportation cost factor $/kW = 

 1.581E-5 * machine rating 2 - 0.0375 * machine rating + 54.7 

Transportation cost = machine rating * cost factor above 

3.4.1.20 Roads, Civil Work 

Estimates for roads and civil work were taken directly from the WindPACT logistics study [3]. 

These estimates include modifications to road widths and crane pads to handle larger machines. 

Cost is a function of machine rating in kW. 

Roads, civil work cost factor $/kW = 

 2.17E-6 * machine rating 2

 – 0.0145 * machine rating + 69.54 

Roads, civil work cost = machine rating * cost factor above 

3.4.1.21 Assembly and Installation 

Data for this relationship come from the WindPACT rotor study, which developed a formula 

based on $/kW of machine rating. This formula was not used. Instead, it was found that a 

relationship based on hub height times rotor diameter gave almost a straight line relationship. 

Though both of these relationships give a close-to-linear relationship, it is believed that a 

function that takes into account the physical size of the largest components will give a more 

direct relationship as these components change in size. This relationship was used in the model. 

It is probable that some type of step function will be more appropriate in the future to take into 

account changes in requirements for different crane models as tower height increases. The data 

to develop such a function may be available in the WindPACT Logistics Study [3], but further 

evaluation is needed. 

Assembly and installation = 1.965 * (hub height * rotor diameter) 1.1736 

3.4.1.22 Electrical Interface/Connections 

Electrical interface covers the turbine transformer and the individual turbine’s share of cables to 

the substation. These data originally came from the WindPACT balance-of-station study [5] and 

were used in this model as originally derived. 

Electrical interface/connection cost factor $/kW = 

 3.49E-6 * machine rating 2

 – 0.0221 * machine rating + 109.7 

21
Electrical interface/connection cost = machine rating * electrical cost factor above 

3.4.1.23 Engineering, Permits 

Engineering and permits covers the cost of designing and permitting the entire wind facility, 

allocated on a turbine-by-turbine basis. These costs are highly dependent upon the location, 

environmental conditions, availability of electrical grid access, and local permitting 

requirements. The formulas provided here were first derived from the WindPACT balance-ofstation cost study [5] and were used in this model without modification. 

Engineering, permits cost factor $/kW = 

 9.94E-4 * machine rating + 20.31 

Engineering, permits cost = machine rating * engineering, permits cost factor above 

3.4.1.24 Levelized Replacement Cost 

Levelized replacement cost is a sinking fund factor to cover long-term replacements and 

overhaul of major turbine components, such as blades, gearboxes, and generators. The 

WindPACT rotor study originally developed this number from a Danish study. Additional crosschecking of this with limited U.S. experience lowered this number for use in the LWST Project. 

The LWST factor is used in this model. This term is based on $/kW/year. Work is under way to 

develop more sophisticated models of this function based on actual wind farm experience in the 

United States. However, as of this writing, no improved estimate is available. 

LRC cost factor = $10.7/kW machine rating 

Annual LRC = machine rating * LRC cost factor above 

3.4.1.25 Operations and Maintenance 

O&M cost covers the day-to-day scheduled and unscheduled maintenance and operations cost of 

running a wind farm. Different wind turbine designs, due to varying complexity, may have 

different O&M costs. However, many new configurations have insufficient operating experience 

to extract a meaningful O&M cost history. Industry cost estimates range from 0.5¢/kWh to more 

than 1¢/kWh. The LWST project in 2002 recommended a cost factor of 0.7 ¢/kWh, regardless 

of machine size or configuration. This allowed studies to determine the impact of other 

technology elements on COE without factoring in O&M cost impacts, which were extremely 

difficult to estimate at the time. New work is under way to evaluate O&M costs based on actual 

wind farm experience in the United States. Preliminary results from these studies indicate that 

the cost per kWh can change significantly between installations of the same machine based on 

wind farm size, tower height or other operational factors. This indicates that a fixed cost per 

kWh for O&M is inappropriate. Work is underway to better quantify these effects and build the 

varying factors into the model. Until this work is concluded, the fixed cost of $0.007kWh is 

being retained as the best estimate available. 

22
Land-based O&M cost in $ = 0.007 * AEP 

3.4.1.26 Land Lease Costs 

Wind turbines normally pay lease fees for land used for wind farm development.. This cost is 

principally based upon the land used by the turbine. The factors applied in different wind farm 

developments vary widely depending on the wind class of the particular site, the nature and value 

of the land, and the potential market price for the wind. No single number or model is currently 

available to predict these costs based on turbine rating, size, or wind class. The number used in 

this model is based on a cost kWh of production making it highly variable with wind class and 

machine performance. This cost was proposed for the LWST Project and defined in the report 

on pathways analysis [8]. While the use of a cost kWh appears inappropriate in the long run, this 

number is currently frozen at $0.00108/kWh until better information is available. 

LLC cost = $0.00108/kWh * AEP 

3.4.2 Offshore Elements 

The turbine cost and scaling model was originally developed for land-based technology. The 

need to evaluate offshore wind technology led to expanding the model. The majority of cost for 

land-based components will not be affected by offshore designs, so the models proposed here for 

turbine subsystems and components are believed to be appropriate for offshore. Some of the cost 

factors used for both land-based and offshore differ for the two different types of installation. If 

there are differences, they are noted below. A few additional elements of cost specific for 

offshore installation and preparation must be added. These factors are discussed below. The 

data for deriving these factors are extremely meager and are primarily based on magazine articles 

or private industry communications converted to scaling factors. Where data are public domain, 

they have been referenced. At this time, the model only handles shallow water installations. In 

most cases, these numbers are very rough estimates, and each area is one in which more in-depth 

research is required for the development of offshore technology. Data provided for the Shallow 

Water installation here are primarily based on a 500 MW wind farm using 167, 3 MW turbines. 

These machines would have a rotor diameter of 90 meters and a hub height of 80 meters. This 

wind farm would be installed in 10 meter water depth 5 miles from shore. Array spacing would 

be 7 rotor diameters by 7 rotor diameters. This is assumed to be a mature design with mature 

component productions. This baseline turbine and the sources of many of the factors below are 

described in greater detail in [13], a draft report to be published by NREL in the near future. 

3.4.2.1 Marinization 

The Marinization component covers special preparation for all components to increase their 

survivability in the extremes of an offshore ocean environment. These preparations include 

special paints and coatings, improved seals for gearboxes, generators, electrical components, and 

electrical connections. It is calculated as a percentage of all turbine costs from the tower up. 

The percentage used in the current model was derived from data published in a range of 

European journals. These numbers suggest marinization factors of between 10% and 15% [10]. 

23
A number of 13.5 % has been chosen for the baseline model. This is a rough estimate and may 

vary with the design. 

Marinization cost = 13.5% of turbine and tower costs. 

3.4.2.2 Offshore Support Structure 

Land-based turbines are normally installed on concrete foundations. Offshore turbines must be 

attached to a form of foundation that extends from sea bed to sea level so that the tower can be 

affixed atop it. These foundations can take several forms, but the most often used is a driven pile 

(a steel pile driven into the sea bed) that protrudes above the water line. The wind turbine tower 

is bolted to the top of this structure. The cost for installing such a pile is normally significantly 

greater than the basic concrete footers used for a land-based turbine. Costs in this model were 

derived from a University of Massachusetts study [11], augmented with private industry 

communications expressed as a function based on machine rating. Effort is under way to 

develop engineering-based models for these structures. 

Offshore support structure cost = 300 * machine rating 

Cost is in 2003 dollars. 

3.4.2.3 Offshore Transportation 

There are two elements of transporting an offshore wind turbine. One element is to get the 

turbine components to the port staging and assembly area. The second is to get the assembled 

turbine to the installation site. This second of these cost elements is covered in the offshore 

installation cost (see Section 3.4.2.5). The cost element in the offshore transportation category 

(somewhat of a misnomer) covers only the cost of bringing the components to the assembly site 

onshore. The costs for 3 to 5 MW turbines show a significant increase over smaller machines 

due to the premiums for moving such large structures over the road or by rail to wind farm sites 

in the central plains. These costs may be significantly reduced by locating fabrication facilities 

close to the port and staging areas. For the estimates in this model, the scaling formulas 

developed in the WindPACT studies were used. These are the same factors as described in 

Section 3.4.1.19 above. 

Offshore transportation cost factor $/kW = 

 1.581E-5 * machine rating 2 - 0.0375 * machine rating + 54.7 

Offshore transportation cost = machine rating * cost factor above 

 

3.4.2.4 Port and staging equipment 

Offshore wind installations require unique facilities to install and maintain operation. Special 

ships and barges are needed for installing piles, setting towers and turbines, laying underwater 

electrical lines, and providing ongoing servicing. Long-term data on these costs are still sketchy. 

The costs available to date are based on private industry communications converted to a scaling 

24
factor based on machine rating, and cross-checked with some data published in European 

journals. Little hard detailed industry data are available. 

Port and staging equipment = 20 * machine rating 

3.4.2.5 Offshore Turbine Installation 

In the future, to help lower costs, specialized equipment should be developed for installing 

turbines on piles or floating platforms. Ocean-going cranes and special barges capable of station 

keeping in currents and winds will be needed to allow erection of the turbine. An alternative to 

special ships with cranes will be land-based cranes loaded onto special barges and maneuvered 

into place for installation. Regardless, it is expected that the installation of very large offshore 

turbines will be more cost effective in the long run than similar land-based installations, due to 

the greater hauling capacity of barges and lifting capacity of offshore crane equipment. For 

shallow water installation, this cost element also includes transport of the turbine from shore to 

the installation site. In the future a separate cost element will need to be developed for transport 

of turbines to sites further offshore. Costs in this model are once again based on private industry 

communications converted to a scaling factor according to machine rating.

Offshore turbine installation = 100 * machine rating 

Cost is in 2003 dollars. 

3.4.2.6 Offshore Electrical Interface and Connection 

In most cases, offshore wind installations will require their own electrical transmission system to 

bring the turbine power to shore. In addition to the connections to shore, underwater electrical 

cables will be required to go from turbine to turbine to gather the turbine power. Some forms of 

redundancy may also be considered for such installations. Because few such large-scale 

installations have been built, very little detailed information for this cost element has been 

developed, though a modeling effort is under way. The costs in this element includes the cost of 

cabling between turbines and the cable to the grid interconnect at the shore. Costs in this model 

are based on calculations and data developed for the first DOE offshore white paper [12]. The 

cost for cable and other equipment for this calculation came from an internal DOE/NREL study 

and a report that has not been published. This number should be used with significant care, as it 

is calculated specifically based on a distance to shore of 5 miles, a water depth of 10 meters, and 

an array spacing of 7 by 7. Changes to any of these factors would be expected to change this 

number significantly, as the electrical cost factor is primarily driven by cable cost. Work is 

underway to develop an improved model that will adjust electrical interconnect costs based on all 

of these factors. It is hoped that this work will be completed in 2007. 

Offshore electrical interface and connection cost = 260 * machine rating 

Cost is in 2003 dollars. 

25
3.4.2.7 Offshore Permits, Engineering, and Site Assessment 

Permitting, developing detailed engineering plans, and measuring wind conditions for an 

offshore site are all more complicated and time consuming than for a land-based site, as there is a 

minimum of experience developed for the process. Initial estimates for these costs are quite 

high, as the first offshore wind farms developed have had to go through an extensive 

developmental processes. The costs in this model are based on private industry communications 

converted to a $/kW scaling factor. During the first of such installations in the United States, 

these costs are expected to fluctuate as new agencies and states become involved in the process. 

However, over time, they would be expected to come down as the process is better understood 

and streamlined. 

Offshore permits, engineering, and site assessment cost = 37 * machine rating 

Cost is in 2003 dollars. 

3.4.2.8 Personnel Access Equipment 

Wind turbines located offshore must be accessed from marine vessels, small boats, or helicopters 

for servicing. The environment will present many hazards for those performing this service. To 

improve the safety for these operations, special personnel access equipment will be required. 

Aside from typical equipment such as for fall protection, servicing may require special boat 

access ramps or docking equipment, lifesaving equipment located at each turbine, special tool 

lifts, and emergency survival equipment in case service personnel are stranded at a turbine. The 

full scope of these requirements will be developed over time, as additional facilities are 

developed and the needs identified. The initial estimates in this document were developed from 

private industry communications and cross-checked with such published industry numbers when 

available. 

Personal access equipment = $60,000 /turbine (regardless of turbine rating) 

Cost is in 2003 dollars. 

3.4.2.9 Scour Protection 

Shallow-water turbines will be mounted on towers or piles that are fixed to the ocean bottom. 

These foundations may be driven piles or large concrete footers sitting on the bottom. In any 

case, currents swirling around the base of the footing will have a tendency to scour bottom 

material from the base, causing danger of foundation failure. To mitigate against such scouring, 

rip rap (graded boulder and rock) may be placed around the base to reduce the effects of such 

currents. Cost for this can be relatively easily estimated depending upon the level of current and 

the nature of the seabed. Cost estimates in this model are currently based on private industry 

communications converted to a scaling factor by machine rating. 

Scour protection = 55 * machine rating 

Cost is in 2003 dollars. 

26
3.4.2.10 Surety Bond 

Offshore installations, once decommissioned at the end of their lifetimes, may present long-term 

navigational hazards. Once developed, it is unlikely that good wind sites will be abandoned. 

However, there is the possibility that older foundation or support structures may need to be 

removed when turbines are replaced. To guarantee that funds are provided for removing these 

older structures, a surety bond is provided for. This is a percentage of the ICC less the offshore 

warranty cost. 

Surety bond cost = 3% (ICC - offshore warranty cost) 

3.4.2.11 Offshore Warranty Premium 

Offshore turbines operate in an extreme environment. Because of this and their remote location, 

many manufacturers believe that providing an adequate warranty will represent a greater risk 

than for land-based installations. As offshore installations become more common and 

operational history improves, warranty cost would be expected to be adjusted appropriately. 

Current warranty estimates are based on private industry communications. Additional study and 

experience is required to improve the current estimate. 

Offshore warranty premium = 15.0% of turbine and tower cost 

3.4.2.12 Offshore Levelized Replacement Cost 

LRC is a sinking fund factor to cover long-term replacements and overhaul of major turbine 

components, such as blades, gearboxes, and generators. Offshore installations are believed to 

carry a higher risk of wear and damage that will require more frequent replacements and 

overhaul. The estimate of LRC for offshore installations has been developed based on private 

industry communications and converted to a scaling factor based on $17/kW. 

Offshore LRC = 17 * machine rating 

Cost is in 2003 dollars. 

3.4.2.13 Offshore Bottom Lease Cost 

As on land, the surface space a turbine occupies is not free. Someone inevitably holds the rights 

to the ocean floor in a particular region. Most of these rights are held by the Federal or State 

governments, and a cost for leasing these sites will be incurred (similar to offshore drilling 

leases). The cost in this model is based on the same approach as the land-based model on a fixed 

cost of $.00108/kWh of production. This estimate may change as a better understanding of 

offshore leasing arrangements is developed. 

Offshore bottom lease cost = 0.00108 * AEP 

27
3.4.2.14 Offshore O&M 

Because of the extreme operating environment, the remote location, and the specialized access 

and servicing equipment (barges, ships, boats) needed, offshore O&M costs are expected to be 

much higher than those for land-based installations, at least during the early period of 

development. The magnitude of these costs will be a strong driver in advancements in turbine 

design and operational reliability. As experience and equipment improve, O&M costs will be 

expected to fall. For this model, initial offshore O&M costs are expected to be almost three 

times that of current onshore estimates. Costs are estimated on a $0.02/kWh basis. 

Offshore O&M cost = 0.02 * AEP 

Cost in 2003 dollars.

3.5 AEP 

The AEP spreadsheet is designed to compute annual energy capture and other related factors for 

a wind turbine specified by certain generic input parameters. Notably, these parameters do not 

include blade geometry, airfoil performance, or even a Coefficient of Power (Cp) versus tipspeed-ratio (λ) curve. Only a peak Cp is given, and the λ at which it occurs. This strategy 

enables parametric studies around the available parameters to be completed.

The AEP spreadsheet works by dividing up the operational range into 1⁄4 m/s bins. In each bin, 

necessary parameters such as hub power, drive-train efficiency, and total energy are computed. 

Important parameters such as energy capture and capacity factor are computed from the column 

totals. 

3.5.1 Inputs 

The inputs include the following: 

• 50-m wind speed 

• Weibull K parameter 

• Rated power 

• Rotor diameter 

• Hub height 

• Altitude above mean sea level 

• Rotor peak Cp, which is called below * Cp

• Tip speed ratio ( λ ) at which occurs, which is called below * Cp

* λ

• Maximum rotor tip speed 

• Region 2 1⁄2 slope 

• Power law shear exponent (shear) 

• Three conversion efficiency constants described below

The following two parameters are specified but could be modified if desired: 

• Cut-in wind speed 

• Cut-out wind speed 

28
The following image represents the top portion of the AEP spreadsheet. 

3.5.2 Computations 

Air density ρ (cell B15) above, at the given altitude (meters) is determined by the equation 

below: 

( ) altitude

altitude

*0065.0288*15.287

288

*0065.0 1*101300

15.287*0065.0

80665.9

−

⎥

⎥

⎦

⎤

⎢

⎢

⎣

⎡

⎟

⎠

⎞ ⎜

⎝

⎛ −

ρ = 

 

Hub-height mean wind speed (B16) is based on the power-law exponent: 

peedwindm heighthub V

sheer

s 50*

50 ⎟ − ⎠

⎞ ⎜

⎝

⎛ = 

Rated hub power (B17) is just the hub power when the turbine is at rated power: 

ratedatefficiency power

rated power 

29
The following image represents the bottom portion of the AEP spread sheet which contains the 

computation matrix that is used to develop the estimated AEP. 

The efficiency columns (Column G in the top portion and H in the bottom portion) are based on 

the concept that most losses can be fit into one of three categories: 

1) Losses that are constant and independent of power level 

a. Such losses include core loss in a transformer, switching loss in a constantswitching-frequency power converter, windage losses in a constant-speed 

motor/generator, constant speed pumps, fans or other “hotel” loads. 

b. Constant losses are undesirable because they absorb power whenever a turbine is 

in operation. Permanent-magnet generators tend to have very low constant losses 

because they don’t require current for magnetization. 

2) Losses that change linearly with power level 

a. Very few losses usually fit this category. Possibilities include a fan whose speed 

is proportional to temperature difference and switching loss in a converter whose 

switching frequency is proportional to load. 

3) Losses that change with power level squared 

a. The most common term with this characteristic is copper losses at constant 

voltage that follow the familiar I2

R formula. Others can include lubrication losses 

in a variable-speed gearbox, certain other gearbox losses, and conduction losses in 

some switch types. 

b. Direct-drive systems might eliminate all of the quadratic losses associated with 

the gearbox, but they also usually have quite a bit of quadratic losses in the 

generator in order to keep the generator small enough to be cost competitive. 

Medium-voltage systems tend to reduce quadratic losses because the voltage is 

higher, which means that the I2

R losses are lower at the same power level. 

30
This leads to the equation for efficiency: 

rated

rated rated rated

P

P

P

P Quadratic PP Constant Linear

P

P

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛ − +⋅+ ⋅

=

2

η 

Efficiency is set to zero if there is an error in computing it, such as when power is zero. 

The first computation column is the wind column (A), called “V” in the equations below. 

The Rayleigh probability column (B) is only provided for reference. The formula is: 

V

V

e

V

V 4

2

2

2

π

π −

 

The next column (C) is the Weibull probability. Its formula uses the Excel Weibull function: 

( )⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

+ K

KVWeibull V

1ln 1 ,, γ 

The Weibull-Betz column (D) computes the binned power of a Betz turbine operating in the 

specified Weibull wind regime: 

27

16

42

1 3

2

WeibullV ⋅⋅ πD

ρ 

The Weibull Cp column (E) computes the binned power of the specified machine with its actual 

Cp and efficiency curve: 

CWeibullV efficiency D

p ⋅⋅⋅ 3

2

42

1 π

ρ 

The turbine energy column (F) is the turbine power times the Weibull probability: 

⋅WeibullP 

The rated wind speed is difficult to compute. Region 2 1⁄2 is essentially a near constant speed 

region, which pulls the rotor off the optimal Cp - λ peak point. Since the shape of the Cp - λ curve 

is unavailable, an assumption is made about the wind speed at which we achieve rated power. 

This point is somewhere between the wind speed at which we would achieve rated power if we 

31
had no region 2 1⁄2 at all, and a linear extrapolation of where region 2 would intersect with rated 

power if its slope were maintained at the value it has when it reaches region 2 1⁄2. From some 

studies of blade element momentum models of large machines, we have, somewhat arbitrarily, 

chosen 2/3 of the distance from the first point to the second point. This can lead to incorrect 

answers for unusual rotor and turbine designs. There is an error cell to indicate when there is no 

region 2 1⁄2, but no method is provided to detect an error when the 2/3 assumption is incorrect. 

The hub power column (G) can be one of four different values: 

 V # cut in 0 

 V # rated CV p

D 3

2

42

1 π

ρ 

 V > rated CV prated

D 3

2

42

1 π

ρ

 V ∃ cut out 0 

Turbine power (I) is hub power times efficiency: 

powerhub ⋅ efficiency

Region 2 hub power (J) is the power the rotor produces if it is always in region 2 (maximum 

power tracking): 

3

*

2

1 ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

D

V k λ where k is the variable-speed torque constant 3*

*5

64λ

πρ CD p 

Region 2 1⁄2 hub power (K) is the power the rotor produces if it is in region 2 1⁄2 (the linear 

connecting region from region 2 to region 3). 

( )t t

t

t atwindV atpower speedwindrated atwind

powerhubrated atpower ω ω

ω

ω − + −

− 

Region 3 hub power (L) is the rated hub power. 

ωm is the rated rotor speed. 

ω0 is the rotor speed at which region 2 hits zero torque: 

slope

m

+ =1 0

ω

ω where slope is the slope in Region 2 1⁄2. 

32
Tm is the rated torque: 

m

m

ratedhubpower T

ω =

ωt is the rotor speed at which region 2 and region 2 1⁄2 intersect. It is derived from the quadratic 

equation: 

a

acbb t 24 2 −−− ω −= 

where 

0

0

0

ωω

ω

ωω

− =

− −=

=

m

m

m

m

T

c

T b

a k

The wind at ωt is given by: 

* *2

*

λ

ωt D 

The power at ωt is: 

 3

t kω

The total turbine energy capture calculated in the top section of the spread sheet (B26) is: 

( ) ( ) ( ) ( )

4

∑ turbineenergy 1−⋅ soilinglosses 1−⋅ sarraylosse 8760 ⋅⋅ tyavailabili

The denominator “4” is to account for the 1⁄4 m/s wind speed bins. Weibull Cp and Weibull Betz 

are similarly the sums of their respective columns, each divided by 4. 

Capacity factor (B27) is: 

ratedpower⋅8760

energycapture 

33
Energy capture ratio (B28) is: 

CWeibull p

energycapture 

The AEP spreadsheet is designed to compute annual energy production and other related outputs 

when the full turbine and rotor design are not known. Only those few inputs shown above are 

known, and one big assumption has to be made to complete the calculations (see the discussion 

above about finding rated wind speed). Therefore, the results from these calculations should be 

treated as approximate. The ability to change the inputs and quickly calculate new values of 

AEP allows fast evaluation of the effect of the input parameters on AEP, but the user must take 

care not to trigger the error cell (no region 2 1⁄2) or go so far off normal as to violate the 2/3 

assumption in the calculation of rated wind speed. 

4.0 Output Examples 

Table 2 is an example of a cost estimate and COE calculation summary from a run of the cost 

model for the land-based 1.5-MW baseline turbine in 2005 dollars. Table 3 is an example of the 

cost estimate and COE calculation summary from a run of the cost model for the offshore 

(shallow water) 3-MW baseline turbine in 2005 dollars. 

34
Table 2. Cost Estimate from Scaling Model: Land-Based, 

1.5-MW Baseline Turbine. 

From Input Page

Machine Rating (kWs) 1500

Rotor Diameter (meters) 70

Hub Height (meters) 65

Land Based Turbine

Cost in $ 2002

Component Component

Costs $1000 Mass

Component kgs

Rotor 237 28,291

 Blades 152 13,845

 Hub 43 10,083

 Pitch mchnsm & bearings 38 3,588

 Spinner, Nose Cone 4 775

Drive train,nacelle 617 43,556

 Low speed shaft 21 3,025

 Bearings 12 679

 Gearbox 153 10,241

 Mech brake, HS cpling etc 3

 Generator 98 5,501

 Variable spd electronics 119

 Yaw drive & bearing 20 1,875

 Main frame 93 19,763

 Electrical connections 60

 Hydraulic, Cooling system 18 120

 Nacelle cover 21 2,351

Control, Safety System, Condition Monitoring 35

Tower 147 97,958

0

TURBINE CAPITAL COST (TCC) 1,036 169,804

Foundations 46

Transportation 50

Roads, Civil Work 79

Assembly & Installation 38

Electrical Interface/Connections 122

Engineering & Permits 32

0

0

0

BALANCE OF STATION COST (BOS) 367 0

0

Initial capital cost (ICC) 1,403 169,804

Installed Cost per kW 935 113,203

 (cost in $)

Turbine Capital per kW sans BOS & Warranty 691 113,203

(cost in $)

Levelized Replacement Cost $ per year 16

O&M $ per turbine/yr 30

Land Lease Cost 5

CAPACITY FACTOR 32.82%

Net ANNUAL ENERGY PRODUCTION Energy MWh (AEP) 4312

Fixed Charge Rate 11.85%

COE $/kWh 0.0476

35
Table 3. Cost Estimate from Scaling Model: Offshore 

(Shallow-Water) 3-MW Baseline Turbine.

From Input Page

Machine Rating (kWs) 3000

Rotor Diameter (meters) 90

Hub Height (meters) 80

Offshore Turbine

Cost in $ 2005

Component Component

Costs $1000 Mass

Component kgs

Rotor 477 50,957

 Blades 319 28,809

 Hub 69 14,842

 Pitch mchnsm & bearings 83 6,162

 Spinner, Nose Cone 6 1,145

Drive train,nacelle 1,425 88,552

 Low speed shaft 59 6,251

 Bearings 32 1,650

 Gearbox 408 20,973

 Mech brake, HS cpling etc 6

 Generator 211 10,426

 Variable spd electronics 266

 Yaw drive & bearing 46 4,312

 Main frame 168 40,426

 Electrical connections 150

 Hydraulic, Cooling system 41 240

 Nacelle cover 38 4,273

Control, Safety System, Condition Monitoring 60

Tower 415 200,762

Marinization (13.50% of Turbine and Tower System) 321

TURBINE CAPITAL COST (TCC) 2,698 340,271

Monopile foundation/Support Structure 1,114

Transportation 281

Port and staging equipment 74

Turbine Installation 371

Electrical Interface/Connect 926

Permits, Engineering, Site Assessment 119

Personnel Access Equipment 64

Scour Protection 204

Surety Bond (Decomissioning - 3.0% of ICC) 176

BALANCE OF STATION COST (BOS) 3,331 0

Offshore Warranty Premium (15.00% of Turbine and Tower System) 357

Initial capital cost (ICC) 6,386 340,271

Installed Cost per kW 2,129 113,424

 (cost in $)

Turbine Capital per kW sans BOS & Warranty 899 113,424

(cost in $)

Levelized Replacement Cost $ per year 55

O&M $ per turbine/yr 215

Bottom Lease Cost 12

CAPACITY FACTOR 38.13%

Net ANNUAL ENERGY PRODUCTION Energy MWh (AEP) 10020

Fixed Charge Rate 11.85%

COE $/kWh 0.0950

36
5.0 References 

[1] Harrison, R.; Jenkins, G.; Cost Modeling of Horizontal Axis Wind Turbines. ETSU 

W/34/00170/REP. University of Sunderland, School of Environment, December 1993 

[2] Griffin, D. A. WindPACT Turbine Design Scaling Studies Technical Area 1 -- Composite 

Blades for 80- to 120-Meter Rotor; 21 March 2000 - 15 March 2001. NREL/SR-500-29492. 

Golden, CO: National Renewable Energy Laboratory, April 2001. 

[3] Smith, K. WindPACT Turbine Design Scaling Studies Technical Area 2: Turbine, Rotor and 

Blade Logistics; 27 March 2000 - 31 December 2000. NREL/SR-500-29439. Work performed 

by Global Energy Concepts, LLC, Kirkland, WA. Golden, CO: National Renewable Energy 

Laboratory, June 2001. 

[4] WindPACT Turbine Design Scaling Studies Technical Area 3 -- Self-Erecting Tower and 

Nacelle Feasibility: March 2000 - March 2001. (2001). NREL/SR-500-29493. Work performed 

by Global Energy Concepts, LLC, Kirkland, WA. Golden, CO: National Renewable Energy 

Laboratory, May 2001. 

[5] Shafer, D. A.; Strawmyer, K. R.; Conley, R. M.; Guidinger, J. H.; Wilkie, D. C.; Zellman, T. 

F.; Bernadett, D. W. WindPACT Turbine Design Scaling Studies: Technical Area 4 -- Balanceof-Station Cost; 21 March 2000 - 15 March 2001. NREL/SR-500-29950. Work performed by 

Commonwealth Associates, Inc., Jackson, MI. Golden, CO: National Renewable Energy 

Laboratory, July 2001. 

[6] Malcolm, D. J.; Hansen, A. C. WindPACT Turbine Rotor Design Study: June 2000--June 

2002 (Revised). NREL/SR-500-32495. Work performed by Global Energy Concepts, LLC, 

Kirkland, WA; and Windward Engineering, Salt Lake City, UT. Golden, CO: National 

Renewable Energy Laboratory, April 2006 (revised). 

[7] Poore, R.; Lettenmaier, T. Alternative Design Study Report: WindPACT Advanced Wind 

Turbine Drive Train Designs Study; November 1, 2000 -- February 28, 2002. NREL/SR-500-

33196. Work performed by Global Energy Concepts, LLC, Kirkland, WA. Golden, CO: National 

Renewable Energy Laboratory, August 2003. 

[8] Bywaters, G.; John, V.; Lynch, J.; Mattila, P.; Norton, G.; Stowell, J.; Salata, M.; Labath, O.; 

Chertok, A.; Hablanian, D. Northern Power Systems WindPACT Drive Train Alternative Design 

Study Report; Period of Performance: April 12, 2001 to January 31, 2005. NREL/SR-500-

35524. Work performed by Northern Power Systems, Waitsfield, VT; General Dynamics 

Electric Boat, Groton, CT; Gear Consulting Services, Cincinnati, OH; and TIAX, Cambridge, 

MA. Golden, CO: National Renewable Energy Laboratory, October 2004 (revised).

[9] - Princeton Energy Resources International . “Consolidated Report on TIO and Pathways 

Analysis”, unpublished NREL Report. 

37
[10] Offshore Wind Energy: Ready to Power a Sustainable Europe, Concerted Action on 

Offshore Wind Energy in Europe, NNE5 – 1999 – 562, Final Report, Delft University of 

Technology, The Netherlands, December, 2001 

[11] Manwell, J. An Overview of the Technology and Economics of Offshore Wind Farms,

Renewable Energy Research Lab, University of Massachusetts, Amherst, 2002 Presentation, 

http://www.mtpc.org/offshore/Meeting3/Manwell1102.pdf#search=%22umass%20offshore%20

wind%20study%22

[12] Butterfield, S.; Musial, W.; Laxson, A. Feasibility of Floating Platform Systems for Wind 

Turbines,. Global Windpower 2004 Conference Proceedings (CD-ROM), 28-31 March 2004, 

Chicago, Illinois. Washington, DC: American Wind Energy Association; Omni Press; NREL 

Report No. PO-500-36049 

[13] Musial, W., Butterfield, S., Laxson, A., Heimiller, D., Ram, B., Large-Scale Offshore Wind 

Power in the United States: Technical Assessment of Opportunities and Barriers, NREL Report 

No. TP-500-40745 

38
F1147-E(12/2004) 

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5a. CONTRACT NUMBER

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4. TITLE AND SUBTITLE

Wind Turbine Design Cost and Scaling Model 

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NREL/TP-500-40566 

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WER6.0703 

6. AUTHOR(S)

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This model intends to provide projections of the impact on cost from changes in economic indicators such as the 

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