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.

Contract No. DE-AC36-08GO28308

Comparative Assessment of 

Direct Drive High Temperature 

Superconducting Generators 

in Multi-Megawatt Class 

Wind Turbines

B. Maples, M. Hand, and W. Musial

Technical Report

NREL/TP-5000-49086

October 2010
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.

National Renewable Energy Laboratory

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Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Comparative Assessment of 

Direct Drive High Temperature 

Superconducting Generators 

in Multi-Megawatt Class 

Wind Turbines

B. Maples, M. Hand, and W. Musial

Prepared under Task No. WER8.1030

Technical Report

NREL/TP-5000-49086

October 2010
NOTICE

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iii

Table of Contents

Introduction..................................................................................................................................... 1

Background ................................................................................................................................. 1

Objective ..................................................................................................................................... 2

Approach ..................................................................................................................................... 2

The NREL Cost and Scaling Model ............................................................................................... 3

History......................................................................................................................................... 3

Early Version Cost and Scaling Model Description ................................................................... 4

Description of Cost and Scaling Model Improvements.............................................................. 5

General..................................................................................................................................... 5

Low Speed Shaft...................................................................................................................... 5

Direct Drive Generator............................................................................................................ 6

Main Frame.............................................................................................................................. 7

Drive Train Efficiency Curves ................................................................................................ 8

Industry Power Curve Data ..................................................................................................... 8

Model Inputs................................................................................................................................... 9

Turbine Design Parameters......................................................................................................... 9

AMSC Supplied Preliminary Designs....................................................................................... 10

Wind Characteristic Input Parameters....................................................................................... 11

AMSC Preliminary Design Comparison ...................................................................................... 11

Assumptions for Comparison.................................................................................................... 11

Component Comparisons.......................................................................................................... 12

Drive Train/Nacelle Assembly .............................................................................................. 12

Generator ............................................................................................................................... 13

Main Frame............................................................................................................................ 15

Low Speed Shaft.................................................................................................................... 17

Gear Box................................................................................................................................ 18

System Comparisons................................................................................................................. 19

Drivetrain Cost Of Energy..................................................................................................... 20

Total Levelized Cost Of Energy (LCOE).............................................................................. 22

Conclusions and Recommendations............................................................................................. 23

References..................................................................................................................................... 26

Appendix A. Fixed Charge Rate Calculation .............................................................................. 29

Appendix B. Sample cost and scaling model output with LCOE calculation ............................. 30

Appendix C. PMDD generator calculations................................................................................ 33
iv

Table of Figures

Figure 1: Drivetrain efficiencies for various drivetrain designs from 6% to 100% of rated 

power............................................................................................................................. 8

Figure 2. Rotor, nacelle, and tower mass for AMSC preliminary designs ranging

from 3.1 to 10 MW. .................................................................................................... 10

Figure 3. Rotor, nacelle, and tower cost for AMSC preliminary designs ranging from 

3.1 to 10 MW. ............................................................................................................. 10

Figure 4. Comparison of overall drive train mass for geared, PMDD, and AMSC turbines. .... 12

Figure 5. Comparison of overall drive train cost for geared, PMDD, and AMSC turbines....... 13

Figure 6. Comparison of generator mass for geared, PMDD, and AMSC turbines................... 14

Figure 7. Comparison of generator cost for geared, PMDD, and AMSC turbines. ................... 15

Figure 8. Comparison of main frame mass for geared, PMDD, and AMSC turbines. .............. 16

Figure 9. Comparison of main frame cost for geared, PMDD, and AMSC turbines................. 17

Figure 10. Comparison of low speed shaft mass for geared, PMDD, and AMSC turbines......... 17

Figure 11. Comparison of low speed shaft cost for geared, PMDD, and AMSC turbines. ......... 18

Figure 12. Gearbox masses for turbines 3-10 MW. ..................................................................... 18

Figure 13. Gearbox costs for turbines 3-10 MW.......................................................................... 19

Figure 14. Efficiency differences between analyzed drivetrains ................................................. 21

Figure 15. Comparison of levelized drive train costs for geared, PMDD, and AMSC turbines.. 22

Tables

Table 1. Overarching turbine parameters used in all three design types. ................................... 9

Table 2. Rotor, nacelle, and tower mass breakdown for AMSC supplied turbines.................. 11

Table 3. Wind characteristic input parameters used for all three drivetrain configurations..... 11

Table 4. Annual energy production in gigawatt hours.............................................................. 21

Table A-1. Offshore wind power project financing scenarios...................................................... 29

Table C-1. PMDD generator calculations..................................................................................... 34
1

Abstract

This paper summarizes the work completed under the CRADA between NREL and American 

Superconductor (AMSC). The CRADA combined NREL and AMSC resources to benchmark 

high temperature superconducting direct drive (HTSDD) generator technology by integrating the 

technologies into a conceptual wind turbine design, and comparing the design to geared drive 

and permanent magnet direct drive (PMDD) wind turbine configurations. Analysis was 

accomplished by upgrading the NREL Wind Turbine Design Cost and Scaling Model to 

represent geared and PMDD turbines at machine ratings up to 10 MW and then comparing cost 

and mass figures of AMSC’s HTSDD wind turbine designs to theoretical geared and PMDD 

turbine designs at 3.1, 6, and 10 MW sizes. Based on the cost and performance data supplied by 

AMSC, HTSDD technology has good potential to compete successfully as an alternative 

technology to PMDD and geared technology turbines in the multi megawatt classes. In addition, 

data suggests the economics of HTSDD turbines improve with increasing size, although several 

uncertainties remain for all machines in the 6 to 10 MW class. 

Introduction

Background

Recent trends in wind energy have shifted toward larger projects using bigger turbines because a

reduced cost of energy (COE) is associated with increased size. Historically, the cost of wind 

energy decreased as turbines grew larger; the result of enhanced engineering design that reduced 

component masses and costs, improved reliability, decreased operation and maintenance (O&M) 

costs, and optimized balance of station (BOS) components. 

The trend toward larger turbines is expected to continue, particularly with offshore projects

where physical size restrictions are less of an impediment. Offshore projects are anticipated to 

utilize larger turbines to take advantage of economy of scale. Currently, offshore projects place 

larger turbines in shallow coastal waters, where the wind resource is typically superior to 

onshore wind resources, thus yielding higher energy production. However, due to the offshore

location of these turbines, the associated operations and maintenance (O&M) and BOS costs are 

typically higher. 

Currently, the world’s largest installed wind turbines, on and offshore, have rotor diameters

reaching 127 meters and nameplate capacities of 5 to 6 MW, though many manufacturers are in 

the process of designing significantly larger machines. American Superconductor (AMSC), a 

worldwide leader in high temperature superconductor (HTS) technologies and products, who is 

also a leader in wind power system engineering, recently teamed with AMSC Windtec, a wholly 

owned subsidiary of AMSC, a leader in wind turbine design, to develop 3.1, 6, and 10 MW high 

temperature superconductor, direct drive (HTSDD) generator wind turbine designs as focused 

cases. The HTSDD generator design is a result of work sponsored by the National Institute of 

Standards and Technology (NIST) Advanced Technology Program (ATP). AMSC Windtec 

developed key technologies for low cost 10 MW class HTSDD generators, in a joint venture 

partnership with TECO Westinghouse Motor Company (TWMC), a leader in rotating machine 

manufacture.
2

AMSC and the National Renewable Energy Laboratory’s (NREL) National Wind Technology 

Center (NWTC) selected point designs derived from the AMCS proprietary conceptual design 

portfolio of the full wind power system. NWTC led the systems analysis, economic modeling, 

and benchmarking in a parallel Cooperative Research and Development Agreement (CRADA). 

This provided specific point designs for the wind turbine system to assess the system’s cost and 

cost of energy (COE). Results from the CRADA provided the vision for the next step, which is a 

demonstration program for a full wind turbine system. 

The main purpose of this CRADA was to combine the NREL and AMSC resources to 

benchmark HTSDD generator technology by integrating the technologies into a conceptual wind 

turbine design, and comparing the design to geared drive and permanent magnet direct drive

(PMDD) wind turbine configurations. The mutually beneficial relationship allowed NREL to 

gain an understanding of the current state-of-the-art HTSDD generator technology from AMSC. 

The NREL relationship provided AMSC with valuable knowledge and implementation through 

NREL’s analysis capabilities including its wind turbine system experience and cost modeling. 

Both AMSC and NREL gained a fundamental understanding of the potential for HTSDD

generator technology to be economically applied to wind turbines. 

The collaboration has long term benefits for both parties through the exchange of data and ideas. 

While the development of HTSDD generators is in a nascent stage, the collaboration also shows

potential for enhancing the development of future wind energy systems in the multi-megawatt 

class for land based systems as a result of lighter weight components that can be more easily 

lifted with conventional cranes. In addition, the HTSDD technology may have greater potential 

for offshore wind turbines in the 6 to 10 MW class, even the possibility of a new class of wind 

turbines designed to operate on floating foundations.

Objective

The primary objectives of this CRADA were to:

1. Further develop the NREL Wind Turbine Design Cost and Scaling Model to represent 

geared and PMDD turbines at machine ratings up to 10 MW

2. Compare cost and mass of AMSC’s HTS wind turbine designs to theoretical geared and 

PMDD turbine designs at 3.1, 6, and 10 MW sizes

Approach

The analysis looks at three turbine designs: a geared, a PMDD, and a HTSDD turbine. The 

geared and PMDD turbines were chosen because they are the two most prominent turbine 

designs installed today. They are indicative of two distinct technology paths that the industry 

may take once wind turbine production becomes more common in the 6 to 10 MW classes. For 

simplicity, all turbines compared in this analysis assume a standard three-bladed, up wind 

configuration with the rotor/nacelle assembly situated on a tubular tower. 

Preliminary results indicated that a more detailed comparison of drivetrain components, through 

scaling relationships, would provide the greatest value to both parties of the CRADA. This was

based on the assumption that all turbines would use the same rotor and tower. A more detailed 

explanation of why this assumption was made is reviewed in the Assumptions for Comparison
3

section. Until further data indicates an alternative approach is warranted, it is assumed that the 

BOS costs for all turbine designs is the same in each power rating across all three drive train 

configurations. 

It was assumed that the large size of the major components, such as blades and towers, would 

make onshore transportation exceptionally expensive. Additionally, AMSC’s design choice of a 

relatively high tip speed resulted in higher sound emissions that could limit onshore locations

due to proximity to residences. Therefore, only offshore turbines are considered in this study 

since transportation size issues and sound emissions are much less of a factor. 

The NREL Cost and Scaling Model

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 by researchers at the University of Sunderland in the UK resulted in a set of scaling tools 

for machines with rotor diameters ranging from 15 to 80 meters [1]. This report contained 

valuable models to predict the impact of machine size on turbine components. 

Beginning in 1999, the U. S. Department of Energy (DOE) began its WindPACT projects. These 

projects were focused on determining the potential technology pathways that would lead to more 

cost-effective wind turbine designs. One of the 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. The 

WindPACT projects culminated in seven principal studies: 

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

• Turbine, Rotor and Blade Logistics [3] 

• 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 
4

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

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

drive train design studies extended this work, each by exploring a number of alternative 

drivetrain (gear box, generator, and 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 the Low Wind Speed Technology 

(LWST) projects [9]. 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. All LWST subcontracts have been completed

[9], 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. 

Beginning in late 2005, researchers at NWTC 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). The second purpose of this work was to provide a baseline tool for evaluating the 

impact of machine design and growth on the cost for proposed offshore wind turbine systems. To 

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

formula source. In the process of compiling these relationships into a computer model and 

comparing them to current technology, a number of deviations were noted between this 2002 

model and current trends. 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.

Early Version Cost and Scaling Model Description 

The DOE/NREL cost and 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 address all potential wind turbine 

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

commercial industry at the time of the models first creation. 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. All cost scaling relationships were developed in a 2002 dollar basis 

for consistency. Most of the data originated in a 2002 dollar. Where cost data were available 

from different years, they were converted to 2002 dollars before the cost and scaling factors were 

developed. Cost data are based on a mature design and a 50 MW wind farm installation, with 
5

mature component production [10]. The model employs an algorithm to escalate component 

costs to alternate dollar year bases using Producer Price Indices at the manufactured component 

level.

Much of the data used to develop scaling functions for geared machines of greater than 1 to 2 

MWs and most PMDD machines are based on conceptual designs and very sparse relationships. 

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 [10]. The WindPACT studies were not intended to be 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, such as 

making single large components into multiple smaller components to ease transportation costs 

and restrictions. This model should be viewed as a tool to help identify such barriers and to 

quantify the cost and mass impact of design changes on components without such innovation. 

With expansion, the model can be used to help designers quantify the net value of the

improvement by any component. 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. 

Description of Cost and Scaling Model Improvements

General

In order to derive a COE comparison table with other wind turbines in the market space, it was 

necessary to be able to estimate the cost and mass of all major wind turbine components, and to 

know how these metrics change with variations in the turbine size. The objective of the CRADA 

largely consisted of updating NREL’s cost and scaling model to represent these variations at 

turbine sizes between 3 and 10 MW. The original model was developed based on wind turbine 

sizes ranging from 750 kW to 5 MW. For this study, extrapolation to larger turbine sizes, up to 

10 MW, was required. Therefore, the drivetrain component models were reevaluated.

When updating the model the following strategies and assumptions were made:

• Smooth functions were developed for updated relations, although the data from which they 

were derived may have contained discrete steps

• Other models and studies were checked to validate final scaling relations.

• Given that most costs were considered to be a function of mass, cost relations were largely 

unaltered

• Where data were available, scaling relations were checked against known commercial 

components

• Scaling relations represent production numbers, not the numbers expected for “one offs”

• All components were assumed to be of standard design, except where specified.

Low Speed Shaft

The formula used to establish the outer diameter of the low speed shaft was based on formulas 

for stress and strain at the main bearing where the shaft has the highest loads, adjusted from the 

University of Sunderland report [1]. Correction factors used in the equations were adjusted from 
6 

their original state by selecting values more typical of larger turbines, to more accurately 

represent low speed shafts of turbines in the multi-megawatt class. The main shaft was assumed 

to be supported by a bearing at both ends, and to consist of a solid cylinder with a small hollow 

center and flanged ends for a bolted connection to the hub and gearbox. Low speed shafts for 

direct drive turbines and turbines utilizing a single bearing solution were not addressed. The 

inner-to-outer-diameter ratio of the main shaft was fixed at 0.1, with the length of the shaft fixed 

at 0.03*Rotor Diameter. The original formula did not take into account the addition of large 

connection flanges at both ends of the shaft; therefore, in this model, a term to add mass for the 

flanges was introduced. It was assumed that the mass of the flanges was 0.25*Mass of Shaft 

without the flanges [19]. A hollowness of 1 and safety factor of 3.25 was used in accordance 

with the original formulas. 

The resulting expressions for the calculation of the low speed shaft’s mass are as follows: 

כ 1.25 ൌ ௦ܯ

ߨ

௦ߩ כ ௦ܮ כ ଶሻܦܫ െ ଶܦܱሺ כ 4

௦ܯ כ 0.25 ൌ௙ ܯ

௙ܯ כ ௦ܯ ൌ ݏݏܽܯ ݈ܽݐ݋ܶ

With: 

Ms = Mass of the shaft 

Mf = Mass of the flanges 

OD = Outer diameter of the shaft 

ID = Inner diameter of the shaft 

The cost of the low speed shaft retained the same relationship from the early version of the cost 

and scaling model; the relationship is 0.0998*(Rotor Diameter) 2.8873[10] in 2002 USD. This was 

developed from data provided in the WindPACT Rotor Study [6]. 

Direct Drive Generator 

The mass of the direct drive generator was updated in the current model to adequately represent 

PMDD generators in the 3 to 10 MW size range, with a standard internal rotor design. The model 

does not currently have the ability to represent innovative PMDD generator designs such as 

“inverted generators” with internal stators. Industry point designs in the range of 1.5 MW to 7 

MW were analyzed for size, mass, torque, and air gap shear stress to develop two scaling 

relations for a PMDD generator. The first scaling relation assumed that the generator would be 

constrained to no more than 4.3 meters in diameter due to transportation underpass and bridge 

limits. The second relation was developed to eliminate the diameter constraint for offshore 

applications where transportation restrictions are less of a constraint or for generators that might 

be manufactured in segments that can be assembled on site. For each relation, a set of points was 

3

2 2 2

* * * 32















 



 



  +  



 = SteelEnduranceLimit

BendingMoment

SteelYieldStress

RotorTorque OD Hollowness SafetyFactor

π
7

calculated and plotted from 1 to 11 MW. A smooth curve fit was then developed for a PMDD 

from each data set to produce the following relations:

Constrained Diameter: Mass = 37.7*Rated Torque (Torque in kNm)

Unconstrained Diameter: Mass = 172.8*Rated Torque0.8 (Torque in kNm)

A more detailed explanation of the PMDD generator calculations can be seen in Appendix C.

The cost of the PMDD generator was unaltered from its previous value of $219.33/kW in 2002 

USD [10]. This multiplier was developed as a ratio between the WindPACT direct drive 

generator rated at 1.5MW and the WindPACT geared drivetrain generators derived in the 

WindPACT Alternative Drive Train Study [8].

Main Frame

Formulas from the University of Sunderland report [1] were used to calculate the mass of the 

main frame for geared turbines. Correction factors used in the University of Sunderland formula 

were adjusted by selecting values more typical of larger turbines, to more accurately represent 

machines in the multi-megawatt class. The calculations for the main frame mass were based on 

estimates of rotor thrust, torque, mass, and area. The masses for each factor, with a bedplate area 

of 0.5*(0.0825*Rotor Diameter)2 and a bedplate weight factor of 2.86 for a modular design, were 

calculated as follows [1]:

Mass from Torque = Bedplate Weight Factor*0.00368*Rotor Torque.

Mass from Thrust = 0.00158*Bedplate Weight Factor*Max Thrust*Tower Top Diameter

Mass from Rotor Weight = 0.015*Bedplate Weight Factor*Rotor Mass*Tower Top Diameter

Mass from Area = 100*Bedplate Weight Factor*Bedplate Area

Total Mass = Σ of all Masses

The mass of the main frame was taken to be the sum of all mass inputs calculated above. 

Additional platform and railing mass and cost calculations from the early version of the NREL 

cost and scaling model remained at .125*Main Frame Mass and 8.7*Platform and Railing Mass,

respectively, and were included in the total mass of the main frame assembly [10]. The main 

frame cost of 9.4885*Rotor Diameter1.9525 was unchanged from the previous relation based on 

the WindPACT reports [6]. Base hardware costs are again unchanged from previous relations of 

0.7*Main Frame Cost and included in the total Main Frame cost [10]. Main Frame calculations 

for PMDD machines assume that direct-drive machines need a smaller main frame that is more 

integrated into the direct-drive generator itself and therefore, the main frame cost and mass for 

direct-drive machines is 55% of that for a geared machine [8]. Final main frame mass outputs 

were then checked against industry data and WindPACT results [6] in the range of 750kW to 

5MW.
8 

Drive Train Efficiency Curves

Efficiency curves were established for alternative drivetrain designs to represent the differences 

in annual energy production between drivetrain design choices. Constant, linear, and quadratic 

style losses were modeled from the WindPACT Alternative Drive Train Study [8] for standard, 

single stage, multi drive (6 generators), and direct drive turbines. 

Efficiencies were calculated as follows:

With:

C = Constant losses

L = Linear losses

Q = Quadratic losses

P = (Power)/(Rated Power)

Except for the standard geared drivetrain, all generators were assumed to be a permanent magnet 

design. Drivetrain efficiencies for all four drivetrain configurations can be seen in Figure 1 

below from 6% of rated power to 100% of rated power. 

Figure 1: Drivetrain efficiencies for various drivetrain designs from 6% to 100% of rated power.

Industry Power Curve Data

Power curves for AMSC’s three turbine sizes were added to the NREL cost and scaling model 

for an accurate comparison, of both annual energy production and capacity factor, to an idealized 

0.6

0.65

0.7

0.75

0.8

0.85

0.9

0.95

1

0 0.2 0.4 0.6 0.8 1

Various Drive Train Efficiencies (%)

P/Prated

Geared PM Direct Drive Single Stage Multidrive (6)

ൌ ߟ

ଶሻܲכܳ൅ܲכܮ൅ܥሺ െ ܲ

ܲ
9 

turbine. Industry power curve data, based on published power curve information, were also 

added to the cost and scaling model to calculate annual energy production for various industry 

turbines. Data from 69 turbines from 21 manufacturers, ranging from 550kW to 5 MW, were 

added to the model to provide a variety of industry turbines for comparison. The data can 

provide information for project planning as well as concept-to-industry comparisons and offers 

planners the ability to switch between various turbines to optimize site performance. 

Furthermore, design concepts and AMSC’s turbines can be compared against market proven 

turbines. It should be noted, however, that these power curves were frequently derived from 

brochure graphics, and their representations provide only a general comparison between turbines 

and should not be used to represent precise turbine output. Official power curve documentation 

from manufacturers is required to fully assess and compare turbine energy production for a given 

wind regime. 

Model Inputs 

Turbine Design Parameters 

To isolate the drivetrain configurations for comparison, turbine parameters were held constant 

for the three turbines in each MW class. Rotor parameters (Diameter, Cp, Tip Speed, and Tip 

Speed Ratio) and hub heights were all taken from the AMSC designs since they are 

representative of potential commercial designs. Rotor design parameters were chosen by AMSC 

based on the existing blade types on the market and the manufacturing capabilities of the 

potential suppliers. Therefore, an aggressive scale of rotor diameter was avoided, and only 

proven blade technology was used in the preliminary designs. As such, scenarios for prototypes 

with smaller diameters were assumed to be more realistic than big rotors requiring “beyond stateof-the-art” rotor blade technology (e.g., nominally blades beyond 75m in length). Therefore, 

turbine sites for the preliminary designs are assumed to be offshore with high wind regimes. This 

approach does not preclude further studies, in which longer blades with improved blade 

technology might be applied, resulting in bigger diameters and improved cost of energy on 

subsequent turbine designs. The turbine design parameters common to all configurations 

investigated in this report are shown in Table 1. 

Table 1. Overarching turbine parameters used in all three design types. 

3.1 MW 6 MW 10 MW 

Rotor Diameter (m) 115 127.4 149 

Hub Height (m) 90 100 140 

Max Cp 0.485 0.476 .495 

Max Tip Speed m/s 75.0 81.8 89.7 

Max Tip Speed Ratio 9.3 9.4 8.6 

Rated Torque (kNm) 2584 5003 8842 

Rated Speed (RPM) 12.46 12.27 11.5 

Number of Blades 3 

Tower Design Steel Tubular 

Foundation Type Monopile 
10

AMSC Supplied Preliminary Designs

As part of the CRADA Task #1, AMSC Windtec supplied preliminary designs for wind turbines 

using AMSC HTSDD generators at the 3.1, 6, and 10MW power ratings. Cost and mass numbers 

were provided for the rotor assembly, drivetrain/nacelle assembly, tower, and turbine total for 

each MW class, as seen in Figures 2-3 and Table 2. Breakdowns for major components of each 

assembly were also provided.

Figure 2. Rotor, nacelle, and tower mass for AMSC preliminary designs ranging 

from 3.1 to 10 MW.

Figure 3. Rotor, nacelle, and tower cost for AMSC preliminary designs ranging from 3.1 to 10 MW.

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

2 4 6 8 10

Component Mass (kg/kW)

Machine Rating (MW)

Rotor Mass Nacelle Mass Tower Mass

$0 

$200 

$400 

$600 

$800 

$1,000 

2 4 6 8 10

Component Cost ($/kW)

Machine Rating (MW)

Rotor Cost Nacelle Cost Tower Cost
11

Table 2. Rotor, nacelle, and tower mass breakdown for AMSC supplied turbines.

Mass (kg) 3.1 MW 6 MW 10 MW

Rotor Mass 58,502 108,967 145,892

Nacelle Mass 139,321 218,854 332,913

Tower Mass 223,390 405,060 950,000

Wind Characteristic Input Parameters

Wind characteristic parameters were held constant for all three turbine configurations. Wind 

characteristics corresponding to an IEC class I offshore wind farm were used. A hub height wind 

speed of 10 m/s was used for all turbines at all rating sizes with a vertical wind shear of 0.1 per 

second. Wind distributions were calculated using a Weibull probability and a Weibull K factor of 

2.1. Availability for the turbines was estimated at 95% and array losses were set to 10%. Wind 

class parameters used for all three drivetrain design configurations are listed in Table 3. 

Table 3. Wind characteristic input parameters used for all three drivetrain configurations.

3.1 MW 6 MW 10 MW

IEC class I

Vave at HH (m/s) 10

VE50 at HH (m/s) 70

Weibull K 2.1

Wind Shear 0.1

Array Losses 10%

Availability 95%

AMSC Preliminary Design Comparison

Assumptions for Comparison

Calculations for the geared and PMDD turbines were performed using NREL’s updated Cost and 

Scaling Model. Data for the HTSDD machines were provided by AMSC as preliminary designs 

at each turbine size. Therefore, the scaling of the PMDD and geared turbines may not include 

design innovations of a comparable level to that of the AMSC HTSDD design. The cost and 

scaling model does not calculate representative main shaft masses or costs for direct drive

configurations due to a lack of detailed design data from commercial machines. For this reason,

it is assumed that the main shaft for the PMDD machine will have the same cost and mass as that 

of the AMSC designs. 

Large scale blade technology has not yet been developed and demonstrated for machines at the 

10 MW level; therefore, rotor diameters, masses, and costs for both the baseline turbines and the 

superconducting turbine use the numbers provided by AMSC for the HTSDD turbine. Similarly, 

all machines in the comparison use tower cost and mass estimates associated with the 

superconducting turbine. It is possible that the tower mass between turbines with different tower 
12

top masses could vary slightly, though heavier nacelle/rotor assemblies do not necessarily 

require heavier towers. The largest design factor for the tower is based on overturning moment 

associated with the thrust on the rotor. Though the tower top mass is taken into account for 

buckling calculations, it is not the largest design driver. The nacelle mass does however affect 

the natural frequency of the tower and should be taken into account during the dynamic analysis 

[11]. Because tower design takes into consideration many dynamic inputs, attempting to account 

for them in the current version of the cost and scaling model was determined to be beyond the 

scope of this project. 

Component Comparisons

Drive Train/Nacelle Assembly

With tower and rotor masses held constant across all configurations, the only variation in cost or 

mass that can be seen is in the Drivetrain/Nacelle assembly. A significant overall drivetrain mass 

difference is observed across all MW ratings between the PMDD turbine and the Geared and 

AMSC turbines as seen in Figure 4. The geared turbine and the AMSC HTSDD turbine exhibit 

similar masses across machine ratings, but it appears that the AMSC turbine has a slight mass 

advantage at the larger machine sizes. The significant mass difference between the PMDD 

turbines and that of the geared and AMSC turbines is heavily dependent on the PMDD generator, 

which could see significant mass reduction, as discussed later in the generator portion of the 

Component Comparison section.

Figure 4. Comparison of overall drive train mass for geared, PMDD, and AMSC turbines.

However, the variation in mass does not directly correlate to a reduction in the drivetrain cost. 

The overall drivetrain costs for all three machine types, as seen in Figure 5, lie relatively close to 

one another, though the cost of the drivetrain for the AMSC turbine rises at a lower rate than that 

of the other two turbines. The geared and PMDD turbines represent simple scaling of technology 

to larger sizes. Design innovations targeted to reduce mass as the size increases are not included 

in the basis scaling relationships. The AMSC turbines represent more detailed preliminary

designs at each MW rating, rather than simple scaling of technology to larger sizes. 

30.00

35.00

40.00

45.00

50.00

55.00

60.00

2 4 6 8 10

Overall Drive Train Mass (kg/kW)

Turbine Rating (MW)

Geared PMDD AMSC
13

Figure 5. Comparison of overall drive train cost for geared, PMDD, and AMSC turbines.

Generator

The largest contributor to the overall drivetrain mass for direct drive machines is the generator. 

Due to the lack of a gearbox, direct drive generators must operate at much lower rpm’s. This 

requires the generator to be larger and more robust to handle the increased torque loads. The 

comparison between direct drive HTS and PM direct drive generators was based on an imposed 

shipping design constraint of 4.3 meter stator diameter. Both machines derive benefit from the 

selection of a larger diameter. The maximum reasonable diameter for an HTS generator is 

generally smaller than a similar PM machine. The design literature [21, 22] proposes diameters 

up to 10 meters for PM machines. If the design literature is correct, the lightweight, 10 m PM 

machine is still greater in weight, by a factor of two, than the 5 m diameter HTS machine. A 

complete comparison between HTS and PM machines would require a family of curves at 

varying diameters and include the cost and weight impact on the integrated nacelle design, which 

is beyond the scope of this study. For a reasonable range of generator diameters, HTS machines 

will be lighter weight. The full load efficiencies for HTS and PM machines are comparable and 

both can be preferentially optimized for size, weight, and/or efficiency. The results, shown in 

Figure 6, demonstrate this. The PMDD generator is the heaviest, the AMSC HTSDD generator is

second heaviest, and the geared turbines generator is the lightest. The roughly 50% reduction in 

mass between the PMDD and AMSC HTSDD generators at 10 MW is one of the core 

advantages of HTS generators.

500

550

600

650

700

750

800

850

900

950

1000

2 4 6 8 10

Overall Drive Train Cost ($/kW)

Turbine Rating (MW)

Geared PMDD AMSC
14

Figure 6. Comparison of generator mass for geared, PMDD, and AMSC turbines.

It should be noted that the PMDD mass figures presented in Figure 6 are of a design with the 

stator on the outside and the rotor on the inside of the generator. With this design, significant 

mass is needed for the support structure to maintain a constant air gap. Several turbine 

manufacturers have designs that attempt to avoid this increased mass by developing innovative 

designs such as an “inverted generator,” in which the stator is on the inside and the rotor is on the 

outside of the generator. Preliminary numbers from a few manufacturers have indicated that 

these innovative designs can be of comparable mass as the AMSC design at ratings around 3 

MW [26].

There is no data available from manufacturers regarding operating speed and efficiency for the 

advanced designs and a comparison between the conservative low speed and high efficiency 

3MW designs in this paper cannot be made. The PMDD generator mass presented in this paper

may be higher than typical direct drive turbines due to the turbine rotor size and operating speed

at 3MW. With a large turbine rotor, the operating speed of the generator must be reduced to 

avoid the associated noise of high tip speeds. The reduction in generator speed increases the 

rated torque and, consequently, the size and mass of the generator. Ideally, PMDD generators 

would benefit from a smaller rotor as compared to a geared or HTSDD design. However, this 

analysis is a comparison of identical turbines with only alterations in the drivetrains from turbine 

to turbine. The 3 MW designs in this paper were on the low end of a set of curves that applied to 

medium voltage high torque machines associated with a projected market for HTS generators 

above 5 MW. The advanced PMDD designs recently introduced into the market are low voltage.

Modification to low voltage machines may be needed if they increase to medium voltage, which 

is projected for the 10 MW class market. An analysis of idealized turbine rotor-to-generator 

configurations for each turbine is beyond the scope of this study.

Though AMSC’s HTSDD generator shows a significant reduction in mass, the advanced HTS 

technology used to achieve the mass reduction is more expensive than standard technology for 

generators. Figure 7 demonstrates this cost impact. It shows the AMSC generator cost as slightly 

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

2 4 6 8 10

Generator Mass (kg/kW)

Turbine Rating (MW)

Geared PMDD AMSC
15

higher than that of the PMDD machine for lower MW classes and roughly the same for the 

largest MW class. However, these curves could change significantly, if the price of copper or 

NeFeB, used in the PMDD generators, increases as it has for the last several years or if the cost 

of HTS generators is driven down by advancements in this relatively new technology. 

Figure 7. Comparison of generator cost for geared, PMDD, and AMSC turbines.

Main Frame

The largest contributor to the overall mass of the drivetrain, for standard gear driven turbines, is 

the main frame. Spanning nearly the entire base of the nacelle, the main frame must support the 

gearbox, generator, and many other drivetrain components in a geared turbine. A direct drive 

machine, such as the PMDD and AMSC HTSDD turbines, is generally self supporting but does

require a limited main frame. As described earlier, it was assumed that the geared turbine 

required a much heavier main frame than direct drive designs. The cost and scaling model rough 

estimates for the direct drive main frame are 55% of that of a geared turbine’s main frame [8]. In 

comparison to the AMSC main frame, the PMDD main frame is probably underestimated

considering that it must support a significantly larger and more massive generator. With such 

sparse data for PMDD turbine main frames, extrapolation of scaling relations beyond the range 

of 3 MW may not be accurate. The main frame of a PMDD turbine is integrated into the 

drivetrain, thus there is a great deal of potential for the design to affect the mass and cost of the 

main frame. A more detailed design of an integrated direct drive generator, with support 

structure, is ultimately necessary to determine an accurate mass and cost of a direct drive main 

frame. A graphical representation of this comparison can be seen in Figure 8.

0

100

200

300

400

500

600

700

800

2 4 6 8 10

Generator Cost ($/kW)

Turbine Rating (MW)

Geared PMDD AMSC
16

Figure 8. Comparison of main frame mass for geared, PMDD, and AMSC turbines.

Associated costs for the main frames vary, most likely because of the lack of detailed design data 

for main frame costs in direct drive turbines. The cost and scaling model calculates the cost of a 

direct drive main frame, including railings and other associated hardware, based on two different 

point designs from the WindPACT Alternative Drive Train Study [8], one at 1.5 MW and the 

other at 3 MW. Again, an extrapolation further than 3 MW, based on two points, may not be very 

accurate. Based on the mass relationship shown in Figure 8, it was expected that the geared main 

frame would show a notably higher cost than that of the direct drive turbines and that the PMDD 

turbine would have a slightly more expensive main frame than that of the AMSC HTSDD. 

However, Figure 9 does not support this. Instead, it shows the AMSC HTSDD main frame at a 

higher cost than that of the PMDD main frame. This discrepancy is likely the result of the 

PMDD main frame cost being calculated from a model, while the AMSC HTSDD main frame 

cost is an actual design estimate. 

0

3

6

9

12

15

18

21

24

27

30

2 4 6 8 10

Main Frame Mass (kg/kW)

Turbine Rating (MW)

Geared PMDD AMSC
17

Figure 9. Comparison of main frame cost for geared, PMDD, and AMSC turbines.

Low Speed Shaft

The low speed shaft for a geared turbine is much different than a low speed shaft for a direct 

drive turbine. A geared turbine uses a low speed shaft and its length is much longer than its 

diameter. The opposite is usually true for direct drive turbines. Due to the lack of detailed design 

data for commercial low speed shafts in direct drive turbines in the cost and scaling model and 

because of their integrated designs, the PMDD turbine was assumed to use the same low speed 

shaft as that provided for AMSC’s HTS turbine. The differences in low speed shaft masses can 

be seen in Figure 10.

Figure 10. Comparison of low speed shaft mass for geared, PMDD, and AMSC turbines.

0

20

40

60

80

100

120

140

2 4 6 8 10

Main Frame Cost ($/kW)

Turbine Rating (MW)

Geared PMDD AMSC

2.00

3.00

4.00

5.00

6.00

7.00

8.00

2 4 6 8 10

Low Speed Shaft Mass (kg/kW)

Turbine Rating (MW)

Geared PMDD AMSC
18

Figure 11 shows a similar pattern for the cost when compared to the mass due to the relatively 

simplistic design of low speed shafts, thus the relation between the cost of the shafts emulates the 

relation between the mass of the shafts.

Figure 11. Comparison of low speed shaft cost for geared, PMDD, and AMSC turbines.

Gear Box

The main difference between a geared turbine and a direct drive turbine is the inclusion or 

exclusion of a gearbox. The gearbox allows for a much lighter, smaller, and cheaper generator,

but it introduces another point of failure and cost to the turbine. Figures 12 and 13 show the 

associated mass and cost, respectively, for gearboxes in the 3-10 MW range.

Figure 12. Gearbox masses for turbines 3-10 MW.

0

10

20

30

40

50

60

2 4 6 8 10

Low Speed Shaft Cost ($/kW)

Turbine Rating (MW)

Geared PMDD AMSC

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

2 4 6 8 10

Gearbox Mass (kg/kW)

Turbine Rating (MW)

Geared
19

Figure 13. Gearbox costs for turbines 3-10 MW.

System Comparisons

It is important to compare wind turbine concepts in a way that captures the full suite of cost 

implications including: capital cost, operating cost, and energy production. The levelized cost 

of energy (LCOE) is a typical metric used to compare wind turbine systems because it captures 

both capital investment and operational impacts over the economic life of the project. The fixed 

charge rate (FCR) approximates the finance cost, including interest and taxes over the economic 

life of the project.

The total LCOE is calculated using the following equation [10]:

LCOE = (FCR x ICC) 

 AEPnet

+ AOE

where LCOE ≡ 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+ 

 AEPnet

(O&M + LRC) 

LLC ≡ land lease cost 

O&M ≡ annual operating and maintenance (O&M) cost 

LRC ≡ annual replacement/overhaul cost

0

50

100

150

200

250

300

2 4 6 8 10

Gearbox Cost ($/kW)

Turbine Rating (MW)

Geared
20

In this analysis, the comparison was focused on the drivetrain components, assuming that 

balance of system costs and operation costs would be similar for all three turbine concepts 

studied (Drivetrain Cost of Energy Section). For reference, an estimated total system LCOE for 

projects anticipated in the U.S. today is presented along with a discussion of the implications in

the simplifying of assumptions made in this analysis (Total Levelized Cost of Energy Section).

Drivetrain Cost Of Energy

Isolating the drivetrain component in the LCOE equation by eliminating the operating cost yields 

the following equation [10]: 

LCOEdt = (FCR x ICCdt

 AEPnet

)

where LCOEdt ≡ levelized drive train cost of energy ($/kWh) (constant $) 

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

ICCdt ≡ initial drive train capital cost ($) 

AEPnet ≡ net annual energy production (kWh/yr) 

With overall drivetrain/nacelle assemblies estimated to have similar masses along with the 

assumption of an equivalent rotor and tower for each turbine configuration, it was assumed that 

there would be no difference in installation equipment needed among the drivetrain designs. 

Because installation equipment and all other balance of station (BOS) costs would be the same, 

this analysis assumed that the only differences in the cost of energy (COE) would result from the 

drivetrain configuration. This impacts the drivetrain cost and annual energy production (AEP).

The difference in drivetrain efficiencies, displayed in Figure 14, can greatly affect the AEP, 

displayed in Table 4 below. Table 4 summarizes the differences in AEP between drive train 

design and turbine size.
21

Figure 14. Efficiency differences between analyzed drivetrains

Table 4. Annual energy production in gigawatt hours

AEP (GWh)

3.1 

MW 6 MW 10 MW

Geared 14.1 22.4 35.8

PMDD 14.3 22.8 36.4

AMSC 14.2 23.4 37.0

The difference in AEP coupled with the difference in the capital cost for each drivetrain leads to 

the approximate levelized cost, in $/kWh, for each drivetrain. One should note that either a 

higher AEP or a lower capital cost for the drivetrain, or the combination of both, will lead to a 

lower levelized drivetrain cost. These costs were calculated using a 14% Fixed Charge Rate 

(FCR). This was based on the assumption, in the project finance structure, that includes a

reduced risk associated with a DOE loan guarantee for an offshore wind energy project in the 

U.S. A description of the FCR assumptions is included in Appendix A. All calculations do not 

take into account production or tax subsidies, which would lower the levelized drivetrain COE.

The differences in LCOE of the drivetrain configurations are shown in Figure 15.

0.6

0.65

0.7

0.75

0.8

0.85

0.9

0.95

1

0 0.2 0.4 0.6 0.8 1

Drive Train Efficiency (%)

P/Prated

Geared PM Direct Drive AMSC
22

Figure 15. Comparison of levelized drive train costs for geared, PMDD, and AMSC turbines.

Total Levelized Cost Of Energy (LCOE)

The full system LCOE takes the AEP, land lease cost, major component replacements, O&M, 

BOS, and drivetrain cost differences into account. The AEP and drivetrain cost differences were 

compared in the previous section at the drivetrain component level. Other costs that could affect 

the comparison among turbine configurations are associated with BOS and O&M costs.

O&M costs for offshore turbines contribute significantly to the wind farm’s LCOE, leading 

many manufacturers to target this area for cost reductions through innovation. Drivetrain design 

differences can lead to different O&M practices. For example, direct drive turbines do not need 

periodic oil changes for the gearbox because the direct drive configuration does not utilize a 

gearbox, reducing the frequency of visits to a particular turbine. For offshore wind projects, high 

reliability is imperative because harsh environment operating conditions significantly impact the 

ability to access and service turbines for unscheduled maintenance. It is anticipated that the 

elimination of O&M costs associated with gearbox maintenance will increase the geared 

turbine’s LCOE relative to the PMDD and HTSDD turbine LCOE. It is possible that the 

increased cooling system requirements that are necessary for HTSDD turbines may lead to 

increased maintenance costs, in which case the LCOE differences between the HTSDD turbines 

and the geared and PMDD turbines would be reduced. Due to the lack of O&M cost data for

offshore HTSDD turbines and, to a lesser extent, PMDD and geared turbines, these operational

cost differences were not quantified in this analysis. 

Major component replacements (represented as LRC in the LCOE equation) have also proven to 

be a significant contributor to a wind farm’s LCOE. For conventional geared turbines, the 

gearbox is a major component that tends to need multiple replacements before the end of the 

turbine’s designed lifetime due to unresolved design problems. The industry has learned from 

these problems over the past two decades. Wind turbine manufacturers, gear designers, bearing 

manufacturers, consultants, and lubrication engineers have worked together to improve load 

prediction, design, fabrication, and operation. This collaboration has resulted in internationally0.015

0.017

0.019

0.021

0.023

0.025

0.027

0.029

2 4 6 8 10

Levelized Drive Train Cost ($/kWh)

Turbine Rating (MW)

Geared PMDD AMSC
23 

recognized gearbox wind turbine design standards [13]. Despite reasonable adherence to these 

accepted design practices, wind turbine gearboxes have yet to achieve their design life goals of 

twenty years, with most systems requiring significant repair or overhaul well before the intended 

life is reached [14, 15, 16]. Since gearboxes are one of the most expensive components of the 

wind turbine system, the higher-than-expected failure rates are adding to the cost of wind energy. 

In addition, the future uncertainty of gearbox life expectancy is contributing to wind turbine 

price escalation. Turbine manufacturers add significant contingencies to the sales price to cover 

the warranty risk due to the possibility of premature gearbox failures [12]. In addition, owners 

and operators build contingency funds into the project financing and income expectations for 

problems that may show up after the warranty expires [17]. It is anticipated that the increased 

cost associated with the gearbox replacement issues will increase the LCOE of geared turbines 

relative to the LCOE of HTSDD and PMDD turbines. Direct drive wind turbines circumvent 

these cost escalations by excluding the gearbox from the design, and rely on the assumption that 

the generator will have fewer maintenance issues. However, if future direct drive configurations 

present issues that would also need major component replacements, the difference in LCOE may 

not be as pronounced. 

For this analysis, it was assumed that the rotor size and weight dominated the BOS cost by 

dictating the type of equipment required for installation of the offshore wind project. Innovative 

concepts for transport and installation of offshore wind turbines could result in more modular 

approaches, where weight difference at the drivetrain component level could become more 

important. In this event, the different BOS cost for similar turbines, with different drivetrain 

configurations, would impact the LCOE. Development of a detailed BOS cost model to conduct 

this type of comparison was outside the scope of this analysis. 

For reference, an estimated system LCOE for anticipated offshore projects in the U.S. is 

presented here, and in more detail in Appendix B. Review of proposed U.S. offshore projects 

and published data from existing and proposed European offshore wind projects indicates that an 

average all-in installed capital investment of $4,131/kW is representative of projects planned for 

installation in 2010. Estimated LCOE was calculated for a 3.6 MW wind turbine, with a 107 

meter rotor diameter at 80 meter hub height, operating in a class 6 wind regime with an average 

wind speed of 8.4 m/s at 50 meters. In this wind regime, an AEP of 12.4 GWh is expected. The 

foundation is a monopile, 25 km from shore, in 10 meter deep water (considered shallow 

offshore).Based on these assumptions, it is estimated that an offshore wind farm installed in 

2010 would see an LCOE of approximately $0.19/kWh, when using a 14% FCR. It is expected 

that the 3.1 MW class turbines studied in this report will exhibit similar LCOE, with slight 

differences as explained in the Drivetrain Cost of Energy section, associated with the different 

drivetrain configurations. 

Conclusions and Recommendations

The main objective of the CRADA was to model expected industry turbines at the 3.1, 6, and 10 

MW classes for comparison of components and LCOE differences with respect to AMSC’s 

HTSDD wind turbine designs. Geared and PMDD wind turbine designs that represent 

conventional wind turbine configurations in the 3 MW class with known track records were used 

as scaling basis for the expected industry turbines at these larger MW classes. An assessment of 

how the HTSDD designs from AMSC compare to the conventional industry turbines was a key 
24 

goal of the CRADA to determine if the concept of a HTSDD generator is economically feasible 

for wind turbines. 

Based on the comparisons made to the conventional PMDD and the geared configurations, 

HTSDD turbines show a strong potential to be competitive with other drivetrain concepts, 

particularly for larger turbine sizes. Based on the cost and performance data supplied by AMSC, 

HTS technology has good potential to compete successfully as an alternative technology to 

PMDD and geared technology turbines in the multi megawatt classes. In addition, the 

economics of HTSDD turbines improve with increasing size, although several uncertainties 

remain in the cost model. The model for the support structure and low speed shaft for PMDD 

turbines is insufficient and, therefore, could create some error but NREL did not feel that these 

errors would be substantial enough to change the conclusion about HTS technology. An analysis 

to further understand the BOS implications was not completed and could also contribute to some 

uncertainty. One effect left for future work is the impact that reduced drivetrain weight would 

have on the overall BOS costs. 

The new technology inherent in HTSDD turbines introduces new components, which do not 

have a long history of operation, particularly in wind turbines and could potentially introduce 

new modes of failure. The uncertainty in the operating costs of HTS technologies should be 

taken into account in assessing the O&M differences between different drivetrain technologies. 

The HTS technology does show an advantage in weight, efficiency, and scalability. HTS may 

also have a greater potential for cost reduction due to innovations that may come from 

maturation of this relatively less developed technology and its application to wind turbines. 

Perhaps the most significant motivation for the development of a superconducting wind turbine 

generator is the assertion by AMSC and others [23, 24, 25] that this technology will enable the 

construction of larger wind turbines. Larger wind turbines mean fewer turbine installations, 

which could result in lower balance of station costs. As noted in Appendix B, the installed 

capital cost is on the order of 4.1 million per MW using the example 3.6 MW rating. Of this 

cost, 34% is uncertainty and estimated risk. If we assume these items distribute evenly between 

the wind turbine and balance of system, we can estimate that the wind turbine is 45% of the 

installed cost and the balance of station is 55% of the installed cost. On a cost per rating basis, 

balance of station costs could be lower for wind farms using fewer large turbines. Since balance 

of station is the dominant installed cost, a 10 MW should result in a reduction in the installed 

cost per MW, relative to 3.6 MW. Additional work is required to quantify this benefit. 

Significant work is still needed in the development of the NREL Cost and Scaling Model for a 

complete comparison of turbine COE. As stated earlier, the entire BOS portion of the model 

needs more data in order to accurately quantify the benefits of turbine design choices, for both 

land based and offshore applications. Additionally, the cost calculations for the low speed shaft 

and the generator should be altered to be a scaling relation of mass and torque respectively, as 

those parameters will ensure a more accurate analysis. Scaling relations for other cost 

components could also use some alteration to a relation that would ensure a more accurate 

analysis. 

The National Renewable Energy Laboratory recommends that American Superconductor 

Corporation produce a HTSDD generator in the 3 to 6 MW scale for a dynamometer test as a 
25 

next step to development. A 3 to 6 MW scale HTSDD generator shows potential to be 

competitive with other drivetrain configurations and provides a pathway to market with current 

wind energy technology without taking the risks associated with a 10 MW platform. Although 

the study did indicate a slight benefit in scaling the HTS drivetrain to 10 MW, the cost 

advantages are not substantial enough across the system to warrant the added risk entering the 

market at a size where other non drive train components are not currently available. A 

dynamometer test would provide a deeper understanding of operational issues and would supply 

AMSC with valuable experience. 
26

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. 

NREL/TP-500-40566. Golden, CO: National Renewable Energy Laboratory, December 2006.

[12] McNiff, B.; Musial, W.; and Errichello, R., Variations in Gear Fatigue Life for Different 

Wind Turbine Braking Strategies,

[13] International Organization for Standardization, Wind Turbines – Part 4: Standard for Design 

and Specification of Gearboxes, ISO/IEC 81400-4:2005, ISO Geneva, Switzerland, February 

2005. 

Solar Energy Research Institute, Golden, Colorado USA, 

1990. 

[14] Windpower Monthly, "Facing up to the Gearbox Challenge: A survey of gearbox failure and 

collected industry Knowledge," Volume 21, #11, November 2005. 

[15] Rasmussen, F., Thomsen, K., and Larsen, T.J., “The Gearbox Problem Revisited”, Risø Fact 

Sheet AED-RB-17(EN), Risø National Laboratory, Roskilde, DK, 2004. 

[16] P. J. Tavner , J. Xiang, F. Spinato

, “

Reliability analysis for wind turbines,”, Wind Energy 

Journal, Volume 10, Issue 1, John Wiley and Sons, July 12, 2006. 

[17] W. Musial, S. Butterfield, and McNiff, B., Improving Wind Turbine Gearbox Reliability

[18] Butterfield, Sandy. (2010) Personal Communication. Senior Engineer, Boulder Wind 

Power.

, 

NREL/CP-500-41548. Golden, CO: National Renewable Energy Laboratory, May 2007.

[19] Fingersh, Lee. (2010) Personal Communication. Senior Engineer, National Wind 

Technology Center.

[20] Schwabe, Paul. (2010) Personal Communication. Financial Analyst, National Renewable 

Energy Laboratory.

[21] D. Bang, H. Polinder, G. Shrestha, J.A. Ferreira, “Review of Generator Systems for DirectDrive Wind Turbines,” Presented at the EWEC conference in Brussels (2008). 

[22] Hui Li, Zhe Chen, and Henk Polinder, “Optimization of Multibrid Permanent-Magnet Wind 

Generator Systems,” IEEE Trans. on Energy Conversion, Vol. 24, No. 1, March 2009.

[23] Converteam Press release 08:00hrs Monday 12th March 2007; 

http://www.converteam.com/converteam/1/doc/News/PressReleaseZenergy12.03.07.pdf “The 

HTS generator will be significantly smaller than conventional generators and just one quarter of 

the weight. This is anticipated to achieve electricity cost savings of around 25%.”

[24] “Superconductor Technology – Generating the Future of Offshore Wind Power”, Markus 

Lesser, RenCon GmbH & Jens Müller, Zenergy Power GmbH, Published at the 27th of May 
28

2009 at the Renewable Energy World Conference and Exhibition, Cologne, Germany 

http://www.zenergypower.com/images/media-coverage/coils-and-magnets/Generating-thefuture-of-offshore-wind-power.pdf 

[25] “SeaTitanTM Wind Turbines The World’s Most Powerful Wind Turbines”, AMSC Windtec 

Press Release; http://www.amsc.com/pdf/SEATITAN_DS_0510_ForWeb.pdf

[26] Fairley, P., “Wind Turbines Shed Their Gears”, Technology Review, April 27, 2010; 

Retrieved September 28, 2010; http://www.technologyreview.com/energy/25188/
29

Appendix A. Fixed Charge Rate Calculation

Given the same initial turbine costs, installed costs, and general conditions, the two COE 

calculations in this estimation differ only in the assumption of the fixed charge rate (FCR). FCR 

allows simplified COE estimates by relying on a single coefficient, calculated from 

comprehensive cash flow modeling. The FCR reflects finance charges, debt or equity repayment, 

construction financing, and cost of capital (among other factors). FCR is representative of a 

specific ownership and cash flow structure and may vary over time. However, a fixed value is 

required for comparisons across technologies and a composite or average FCR may be used to 

represent an array of financing structures. Both scenarios assume 3% inflation. Scenario one 

assumes a 30% return on equity (ROE), and scenario 2 assumes a 20% ROE. The ROE is high in 

both scenarios to account for risk associated with the initial offshore wind projects. The 

financing scenario for the land-based reference turbines have a lower average FCR of 12%,

because industry and U.S. banks have experience with land-based projects and there are fewer 

unknowns. 

The first financing scenario assumes that offshore project developers secure a DOE federal loan 

guarantee for project debt. If an offshore wind project developer receives a DOE loan guarantee, 

the developer would have a significantly lower cost of capital relative to all equity financing, and 

therefore, a lower estimated weighted average cost of capital (WACC). The loan guarantee 

offered by the U.S. federal government is assumed to cover approximately 64% of project capital 

costs, at a 6% interest rate, while the remaining 36% is assumed to be covered by equity 

contributions at an ROE of 30%. This combination of guaranteed debt and diminished equity 

investment results in a WACC of 13.3%, which translates to a 14% FCR. 

The second scenario has an FCR of 22%. This assumes that the project would be 100% equity 

financed, with no loan guarantee, and an IRR of 20%. This raises the WACC for the project to 

20% (as compared to 13.3% in the previous scenario). Despite the fact that ROE expectations 

greater than 20% have been reported to NREL, 20% is utilized here because a higher WACC is 

assumed to be cost prohibitive. 100% equity financing, with a 20% ROE, translates to an FCR of 

approximately 22% [20].

Table A-1. Offshore wind power project financing scenarios

Scenario 1: DOE Loan Guarantee

Rate of 

Return/Interest 

Rate

Capital %

Equity 30% 36%

Debt 6% 64%

WACC 13.3%

Inflation 3%

FCR 14%

Scenario 2: 100% Equity Financing

Rate of 

Return/Interest 

Rate

Capital %

Equity 20% 100%

Debt N/A N/A

WACC 20%

Inflation 3%

FCR 22%
30

Appendix B. Sample cost and scaling model output with LCOE 

calculation

From Input Page

Machine Rating (kWs) 3600

Rotor Diameter (meters) 107

Hub Height (meters) 80

Offshore Shallow Water < 30 meters

Cost in $ 2008

Componen

t Component

Component

Costs 

$1000 Mass

kgs

Rotor 821 79,436

 Blades 536 47,711

 Hub 124 20,853

 Pitch mechanism & bearings 152 9,413

Spinner, Nose Cone 8 1,459

Drive train, nacelle 2,177 141,902

Low speed shaft 110 19,467

Bearings 67 3,037

Gearbox 596 26,153

Mechanical brake, HS coupling etc 7 716

Generator 293 12,335
31

Variable speed electronics 352

Yaw drive & bearing 92 7,651

Main frame 311 67,212

Electrical connections 247

Hydraulic, Cooling system 56 288

Nacelle cover 47 5,043

Control, Safety System, and Condition Monitoring 66

Tower 805 284,353

Marinization (10.00% of Turbine and Tower System) 387

TURBINE CAPITAL COST (TCC) 4,256 505,691

Monopile Foundation/Support Structure 1,636

Turbine Transportation 552

Port and Staging Equipment 109

Turbine Installation 545

Electrical Interface/Connect 1,576

Permits, Engineering, Site Assessment 142

Personal Access Equipment 64

Scour Protection 300

Surety Bond (Decommissioning - 3.0% of ICC) 275

BALANCE OF STATION COST (BOS) 5,198

Offshore Uncertainty 2,670

Initial U.S. Project Risk 2,168
32

Offshore Warranty Premium (15.00% of Turbine and Tower 

System) 580

Initial capital cost (ICC) 14,873 505,691

Installed Cost per kW 4,131 140,470

(cost in $)

Turbine Capital per kW sans BOS & Warranty 1,182 140,470

(cost in $)

Levelized Replacement Cost $ per year 65

O&M $ per turbine/yr 264

Bottom Lease Cost 15

CAPACITY FACTOR 39.33%

Net ANNUAL ENERGY PRODUCTION Energy MWh (AEP) 12403

Fixed Charge Rate 14.00%

COE $/kWh 0.1871
33 

Appendix C. PMDD generator calculations 

Machine rating, rotor diameter, and tip speed were chosen and then used to calculate the turbines 

rated RPM and torque. As an average from the WindPACT Advanced Wind Turbine Drive Train 

Design Study [7] and other proprietary information, an air gap shear stress of 42 kN/m2

 was 

assumed in conjunction with the torque and corresponding generator diameter to calculate the 

generator length. Once the length and diameter of the generator was known, assuming an 

average constant generator density of 3,175 kg/m3

, or variable generator density derived from the 

same sources [7], the overall mass of the generator, including all support structures and housing, 

was calculated. The following formulas were used to complete Table 6 below. 

 ൌ ܮ

ܶ

ܦቀ כ ߨ2

2ቁ

ଶ

௦ܵ כ

ܵ௚ ൌ 

௧ܵ כ 60

௕ܦכߨ

ܶ ൌ

ܴ כ 30

௚ܵכߨ

൬ כ ߨሺ כ ௖ܦ ൌ௖ ܯ

ܦ

2

൰

ଶ

ሻܮ כ

൬ כ ߨሺ כ ௩ܦ ൌ ௩ܯ

ܦ

2

൰

ଶ

ሻܮ כ

ହ଻ି.ܦ כ 10169 ൌ ௩ܦ

With: 

L = Length of the Generator 

T = Torque of the Generator 

R = Turbine Rating 

D = Diameter of the Generator 

Db = Blade Diameter 

Dc = Constant Density 

Dv = Variable Density 

Ss = Generator Air Gap Shear Stress 

Sg = Speed of the Generator 

St = Tip Speed 

Mc = Constant Density Generator Mass 

Mv = Variable Density Generator Mass 
34

Table C-1. PMDD generator calculations

Input Output

Rating 

(kW)

Blade 

Diameter 

(m)

Tip 

Speed 

(m/s)

PMDD 

Generator 

Diameter 

(m)

Shear 

Stress

(kN/m2)

PMDD 

Generator 

Length 

(m)

Speed 

(rpm)

Torque 

(kNm)

Constant 

Density 

Mass 

(kg)

Variable 

Density 

Mass 

(kg)

1000 55.0 75.0 3.5 42.0 0.45 26.04 367 13,817 17,379 

2000 80.0 75.0 4.0 42.0 1.01 17.90 1067 40,196 45,751 

3000 90.0 75.0 4.3 42.0 1.47 15.92 1800 67,831 73,139 

4000 110.0 80.0 4.3 42.0 2.25 13.89 2750 103,631 111,740 

5000 120.0 80.0 4.3 42.0 3.07 12.73 3750 141,315 152,372 

6000 127.5 80.0 4.3 42.0 3.92 11.98 4781 180,176 194,275 

7000 133.0 85.0 4.3 42.0 4.49 12.21 5476 206,375 222,523 

8000 138.0 90.0 4.3 42.0 5.02 12.46 6133 231,128 249,213 

9000 144.0 90.0 4.3 42.0 5.90 11.94 7200 271,324 292,555 

10000 149.0 90.0 4.3 42.0 6.78 11.54 8278 311,939 336,348 

11000 155.0 90.0 4.3 42.0 7.76 11.09 9472 356,950 384,881 
F1147-E(10/2008)

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4. TITLE AND SUBTITLE

Comparative Assessment of Direct Drive High Temperature 

Superconducting Generators in Multi-Megawatt Class Wind 

Turbines

5a. CONTRACT NUMBER

DE-AC36-08-GO28308

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6. AUTHOR(S)

B. Maples, M. Hand, and W. Musial

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NREL/TP-5000-49086 

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WER8.1030

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14. ABSTRACT (Maximum 200 Words)

This paper summarizes the work completed under the CRADA between NREL and American Superconductor 

(AMSC). The CRADA combined NREL and AMSC resources to benchmark high temperature superconducting direct 

drive (HTSDD) generator technology by integrating the technologies into a conceptual wind turbine design, and 

comparing the design to geared drive and permanent magnet direct drive (PMDD) wind turbine configurations. 

Analysis was accomplished by upgrading the NREL Wind Turbine Design Cost and Scaling Model to represent 

geared and PMDD turbines at machine ratings up to 10 MW and then comparing cost and mass figures of AMSC’s 

HTSDD wind turbine designs to theoretical geared and PMDD turbine designs at 3.1, 6, and 10 MW sizes. Based on 

the cost and performance data supplied by AMSC, HTSDD technology has good potential to compete successfully as 

an alternative technology to PMDD and geared technology turbines in the multi megawatt classes. In addition, data 

suggests the economics of HTSDD turbines improve with increasing size, although several uncertainties remain for 

all machines in the 6 to 10 MW class.

15. SUBJECT TERMS

Superconducting; Direct Drive; Permanent Magnet; Design Cost and Scaling Model; Wind Turbine

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