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

Data Collection for Current 

U.S. Wind Energy Projects: 

Component Costs, Financing, 

Operations, and Maintenance 

January 2011 – September 2011

M. Martin-Tretton, M. Reha, M. Drunsic, 

and M. Keim

DNV Renewables (USA) Inc.

Seattle, Washington

Subcontract Report

NREL/SR-5000-52707

January 2012
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

1617 Cole Boulevard

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303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Data Collection for Current 

U.S. Wind Energy Projects: 

Component Costs, Financing, 

Operations, and Maintenance 

January 2011 – September 2011

M. Martin-Tretton, M. Reha, M. Drunsic, 

and M. Keim

DNV Renewables (USA) Inc.

Seattle, Washington

NREL Technical Monitors: Paul Schwabe and Suzanne Tegen

Prepared under Subcontract No. ADB-1-11427-00

Subcontract Report

NREL/SR-5000-52707

January 2012
This publication received minimal editorial review at NREL.

NOTICE

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Data Collection for Current U.S. Wind Energy Projects: 

Component Costs, Financing and Operations and Maintenance

DNV Renewables (USA) Inc. 

1809 7th Avenue, Suite 900

Seattle, WA 98101 USA

Tel: 1-206-387-4200

Fax: 1-206-387-4201

http://www.dnv.com/windenergy

Prepared For:

National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, Colorado 80401

Date of First Issue: May 24, 2011 Project No. PP004318

Report No.: DDRP0073 Organization Unit: ACGUS368

Version: Revision Date: October 10, 2011

Summary:

The National Renewable Energy Laboratory retained DNV to prepare this report to supplement the Excel 

workbook developed under subcontract no. AGB-1-11427 dated January 18, 2011. 

Prepared by: Marina Martin-Tretton

Technical Consultant

Signature

Prepared by: Meghan Reha

Engineer

Signature

Prepared by: Michael W. Drunsic

Head of Section

Signature

Verified & 

Approved by: 

Michael Keim, 

Head of Section

Signature
ii

Acknowledgements

This work was funded by the U.S. Department of Energy’s (DOE’s) Wind and Water Power 

Program. The authors thank the individuals who reviewed various drafts of this report including 

Maureen Hand, Eric Lantz, Ben Maples, Paul Schwabe, and Suzanne Tegen of the National 

Renewable Energy Laboratory (NREL) and Jeroen Dolmans of DNV Renewables. The authors 

also offer their gratitude to Denise Fisher in NREL’s Communications Office for providing 

editorial support. 
iii

Table of Contents

1 ABSTRACT ............................................................................................................................ 1

2 INTRODUCTION.................................................................................................................. 2

3 O&M COST MODEL SCENARIOS ................................................................................... 2

3.1 Scenarios - Method and Assumptions ........................................................................ 2

3.2 Results: Reference Component Replacement Scenario .............................................. 5

3.3 Results: High Failure, 100% Replacement, and Serial Failure Scenarios .................. 6

4 2010 COMPONENT COST UPDATE ................................................................................. 8

4.1 Component Costs – Methods and Assumptions ......................................................... 9

4.2 Results: Component Cost .......................................................................................... 12

4.3 O&M Arrangements ................................................................................................. 15

4.4 Component Cost 2005 – 2010 Historical Trend ....................................................... 15

5 PROJECT FINANCING ..................................................................................................... 17

5.1 Financing Structures ................................................................................................. 17

5.2 Capital Availability and Cost of Capital ................................................................... 21

5.3 Empirical Findings on Financial Metrics .................................................................. 22

6 REFERENCES ..................................................................................................................... 24
iv

Tables

Table 3-1. O&M Cost Model 20 Year Failure Rate Inputs for All Scenarios ............................ 4

Table 3-2. Cost Comparisons to Reference Costs for Each Scenario ......................................... 6

Table 4-1. Parts Categories by System ..................................................................................... 10

Table 4-2. Annual Labor Rates ................................................................................................. 11

Table 4-3. 2010 Component Cost Data 1.5 MW – 2.0 MW ..................................................... 13

Table 4-4. 2010 Component Cost Data 2.1 MW – 3.0 MW ..................................................... 14

Table 4-5. 2005 – 2010 Component Cost Trend ....................................................................... 16

Figures

Figure 3-1. Reference Failure Rates, Five Year Average O&M Costs ...................................... 6

Figure 4-1. Wind Turbine Manufacturers’ Share of 2010 U.S. Wind Power Installations ........ 9

Figure 4-2. Cumulative Inflation Rate 2005 – 2010 ................................................................. 17
1 

1 ABSTRACT

DNV Renewables (USA) Inc. (DNV) used an Operations and Maintenance (O&M) Cost Model 

to evaluate ten distinct cost scenarios encountered under variations in wind turbine component 

failure rates. The O&M Cost Model used in the analysis was developed for the National 

Renewable Energy Laboratory and is detailed in the 2008 report, Development of an Operations 

and Maintenance Cost Model to Identify Cost of Energy Savings for Low Wind Speed Turbines 

[1]. 

The analysis considers 1) a Reference Scenario using the default part failure rates within the 

O&M Cost Model, 2) High Failure Rate Scenarios that increase the failure rates of three major 

components (blades, gearboxes, and generators) individually, 3) 100% Replacement Scenarios 

that model full replacement of these components over a 20 year operating life, and 4) Serial 

Failure Scenarios that model full replacement of blades, gearboxes, and generators in years 4 to 6 

of the wind project. DNV selected these scenarios to represent a broad range of possible 

operational experiences. 

The three High Failure Scenarios showed relatively little change from the Reference Scenario. 

The 100% Replacement and Serial Failure Scenarios showed much larger increases in overall 

costs relative to the High Failure and Reference Scenarios. The magnitude of the increase varied 

by component; the largest increase resulted when the blade failure rate was modified and the 

smallest increase resulted when the generator failure rate was modified. 

DNV updated the component cost data in the O&M Cost Model based on information from 

suppliers and actual receipts from recent component replacement work. A trend analysis 

comparing the 2010 component cost to data from 2005 shows no clear pattern of price changes 

and different changes by component type. 

Also in this report, DNV summarizes the predominant financing arrangements used to develop 

wind energy projects over the past several years and provides summary data on various financial 

metrics describing those arrangements. The summary is based on projects developed in 2010 and 

2011. The financial metric information reflects a significant increase in financed projects using 

term debt and the monetized version of the investment tax credit since 2009, when compared to 

the number of projects financed using tax equity investments in 2006 and 2007. The review of 

these metrics suggests a more consistent debt market, with largely equivalent terms across 

projects, compared to tax equity financing arrangements that vary widely from project to project.
2 

2 INTRODUCTION

The National Renewable Energy Laboratory (NREL) retained DNV under Subcontract No. 

AGB-1-11427 to prepare an Excel workbook with wind energy component replacement data for 

U.S. wind energy projects. The inputs included component replacement costs, financing metrics, 

and O&M parameters. This report provides a narrative description of DNV’s work under this 

agreement. It describes the model scenarios considered, the updated component costs from 

previous analyses, historical trends, and various aspects of project financing in 2010 and 2011. 

3 O&M COST MODEL SCENARIOS 

DNV created ten unique O&M scenarios to demonstrate the impact of various major component 

failure rates on O&M costs. The default rates and costs were based on data gathered from 

operating projects and industry component failure testing. The data is detailed in NREL's report, 

NREL/SR-500-40581, titled Development of an Operations and Maintenance Cost Model to 

Identify Cost of Energy Savings for Low Wind Speed Turbines, published in January 2008 (the 

O&M Model Report) [1]. This report accompanied the original model developed for NREL. It 

states, in part: 

“The model estimates parts use by applying two types of failure rates to selected 

components, or categories of components. The first type of failure event is random, 

and is represented by a constant failure rate. The model assumes by default that 5% of 

the blades and gearboxes, and 10% of the generators, will fail over the 20-year life of 

the project because of uncontrollable circumstances such as lightning strikes, 

manufacturer defects, operational errors, or servicing omissions and errors. 

The second type of failure event is wear out or deterioration, and is a two-parameter 

Weibull distribution. This distribution is commonly used in reliability studies as it 

allows for variation of the scale as well as the shape of the failure distribution. 

Weibull distributions are intended to describe failure rates for a given population of 

like components. Generally the most reliable data are obtained from exercising the 

components in actual or simulated conditions that are consistent over time. In an 

actual application, however, the parts that fail are replaced, so that the population 

eventually becomes a combination of components with varying periods of operation. 

At some point in time past the characteristic life, the instantaneous failure rate will 

oscillate about, and finally approach, a constant value.” 

3.1 Scenarios - Method and Assumptions

The O&M Cost Model requires input assumptions of project and turbine characteristics. In all 

scenarios, DNV assumed that the following inputs represent a typical project: 100 turbines, 36% 

net capacity factor, 1.5 MW turbine rating, 80 m hub height, electric pitch control, and partial 

power conversion. 

Specifying these project and turbine characteristics, DNV used the default failure rates within the 

model to construct a Reference Scenario to represent the baseline O&M costs. From a design 
3 

perspective, major components are certified to a 20 year design life. In practice, however, most 

turbine components experience failure before 20 years and the failure rate varies by component.

Failure inputs to the O&M Cost Model can be modified by the user. The standard assumptions 

include a 5% catastrophic failure rate for blades and gearboxes and a 10% catastrophic failure 

rate for generators during the life of the turbine. Such catastrophic failures are considered to be 

the result of uncontrollable circumstances including, but not limited to, manufacturing defects 

and operational errors. 

In addition to the baseline failure rate, DNV modeled the considerable uncertainty of actual 

O&M costs due to factors not easily accounted for, such as variations in O&M practices, site 

conditions, like icing, extreme temperatures and environments, variations in individual turbine 

inflow conditions relative to the turbine's International Electrotechnical Commission (IEC) 

classification, and price ranges in the component costs. These uncertainties are estimated by 

evaluating O&M costs using a 30% higher parts failure rate and a 30% lower parts failure rate. 

DNV varied the blades, gearboxes, and generator failure rates from the default rates for three 

distinct scenarios. DNV selected these three components and scenarios based on proprietary 

wind industry data to represent a broad range of possible operational experiences. These 

permutations of components and scenarios resulted in nine additional cases. Once again, the 

uncertainty in O&M costs is represented with a 30% higher and lower component failure rate

relative to the specific scenario discussed below. 

High Failure Rate Scenarios: DNV increased the individual component failure rate to three 

times (3x) the reference failure rate of a specified component. For example, the default failure 

rate for blades in the model is 5%; therefore, the High Blade Failure Scenario used a 15% failure 

rate for blades and the default failure rate for all other components. Similarly, the High Gearbox 

Failure Scenario used a 15% failure rate for gearboxes, and default failure rates for all other 

components. The High Generator Failure Scenario used a 30% failure rate for the generator, and 

default failure rates for all other components. 

100% Replacement Scenarios: DNV increased the failure rate to 100% for a specified 

component, distributing the failures evenly throughout the entire 20 year project life. In the 

100% Failure Scenarios, the 30% uncertainty band represents failures at 130% and 70% over 20 

years. For example, in the 100% Blade Replacement Scenario, the baseline represents 300 blade 

replacements, or 15 replacements per year. While the 30% Higher Parts Failure Scenario 

represents 390 blade replacements, and the 30% Lower Parts Failure Scenario represents 210 

blade replacements. The components experiencing 100% replacement have a zero defect rate 

after the replacement.

Serial Defect Scenarios: DNV increased the component failure rate to 100%, distributing these 

failures throughout operating years 4 through 6. This scenario simulates how O&M costs are 

distributed in the event of a serial failure occurring outside of a warranty period. Components not 

experiencing serial failure use the default failure rates, which are applied over the entire project 

life. As with the 100% Replacement Scenarios, the components experiencing a serial defect have 

a zero defect rate after the serial defect remediation is complete. DNV assumed that the cost of 

serial replacements would be the cost of the components plus the cost of installation including a 
4 

crane, labor, and other associated costs. These costs were distributed over a typical replacement 

period of three years with 33 or 34 turbines receiving replacements per year. Years 4 to 6 were 

selected as representative operating years because they occur after a typical original equipment 

manufacturers (OEM) warranty period. 

The failure rate inputs to the O&M Cost Model for the scenarios described above are shown in 

Table 3-1. 

Table 3-1. O&M Cost Model 20 Year Failure Rate Inputs for All Scenarios

Blade Failure 

Rate (%)

Gearbox Failure 

Rate (%)

Generator 

Failure 

Rate (%)

Reference Scenario 5 5 10 

High Blade Failure Scenario 15 5 10

High Gearbox Failure Scenario 5 15 10

High Generator Failure Scenario 5 5 30

100% Blade Failure Scenario 100 5 10

100% Gearbox Failure Scenario 5 100 10

100% Generator Failure Scenario 5 5 100

Serial Blade Failure Scenario* 100 5 10

Serial Gearbox Failure Scenario* 5 100 10

Serial Generator Failure Scenario* 5 5 100

* In the Serial Failure Scenarios, 100% component failures are modeled to occur in years 4 to 6 rather than evenly 

spread across the 20 year operating life (see description in text above). 

Under all scenarios, DNV assumed that blades, gearboxes, and generators would be replaced as 

complete units. Rebuilt gearboxes and generators are common in the wind industry and the price 

of the replacement components in the O&M Cost Model is lower than the price of new 

components. Depending on the nature of the damage and when it is detected, gearbox 

maintenance ranges from repair or replacement of subcomponents to replacement of the entire 

gearbox. In many cases, subcomponents can be repaired prior to catastrophic failure, if the 

damage is identified in time. Such repairs often avoid the cost of crane deployment. Condition 

monitoring systems and inspections can help identify failures prior to a catastrophic event. It is 

uncommon to purchase refurbished blades; therefore, only new blade costs are considered in this 

analysis.

The O&M Cost Model does not explicitly include economies of scale cost savings for crane 

costs. However, the cost of a crane rental is a significant contributor to the replacement cost of 

most major components. One way project operators reduce their costs is by performing multiple 

repairs that require a crane at the same time [1]. Therefore, DNV has included some economies 

of scale savings in this analysis. The general scheme used for crane economies of scale is that

mobilization and demobilization costs are reduced per replacement job since the crane remains 

on site and in operation for an extended period of time, allowing these costs to be distributed

over multiple jobs. In this analysis, DNV assumed that if more than four major failures occurred 

in a given year, all subsequent crane events for that year would be discounted. Larger discounts 

result as the number of crane events increases, until a minimum per-event crane cost is reached. 

As outlined in the O&M Model Report, turbines with integrated cranes that are capable of 
5 

replacing wind turbine generators (e.g., nacelle mounted lifts) are not considered in the current 

model [1]. 

DNV used the updated component costs described in Section 4 of this report as input cost 

assumptions in the ten scenarios. In these scenarios, failures of blades, gearboxes, and generators 

were considered to be the most relevant major components. Additional components that could be 

considered include the bed-frame and main bearings. However, replacement of these components 

is rare compared to the replacement of blades, gearboxes, and generators. 

In addition to other components, two invariable cost items in the above scenarios are regularly

scheduled maintenance (included through the labor budget and the consumables line items in the 

model) and a small budget for the maintenance of roads, meteorological equipment, and other 

facility maintenance. These items are held constant across the scenarios. Substation maintenance 

costs are not currently included in the model. These costs are highly variable from project to 

project and, in some cases, are borne by the off-taking utility instead of the project. There are 

various other costs when operating a wind project, such as insurance, taxes, and purchased 

electricity, that are not included in the model. 

A full listing of all component failure rates and cost assumptions is in Appendix A. 

3.2 Results: Reference Component Replacement Scenario

The results of the Reference Scenario are presented in Figure 3-1 as five year average O&M 

costs. As previously described, the uncertainty in the O&M costs is represented by the 30% 

higher and 30% lower parts failure rate band. The Reference Scenario results show increasing 

O&M costs over time. There is a slightly greater difference between the baseline and the 30% 

high case than between the baseline and the 30% low case due to the accelerated parts failures in 

the 30% high case which leads to a non-linear compounding effect in the total number of 

components replaced over 20 years. 
6 

Figure 3-1. Reference Failure Rates, Five Year Average O&M Costs 

3.3 Results: High Failure, 100% Replacement, and Serial Failure Scenarios

The results of the High Failure, 100% Replacement and Serial Failure Scenarios are shown in

Table 3-2 and in Figure 3-2. In Figure 3-2, the High Failure, 100% Replacement and Serial 

Failure Scenarios are shown as solid black lines, while the 30% cost uncertainty band is shown 

with dashed black lines. For comparison purposes, the Reference Scenario is presented as solid 

grey lines while the uncertainties are shown as dashed grey lines. The Reference Scenario is

identical in each plot.

Table 3-2. Cost Comparisons to Reference Costs for Each Scenario

Average Cost per Period (2011 $/Turbine)

 Year

1-5 

Year

6-10

Year

11-15

Year

16-20 20-Year Average

Deviation from 

Reference 

Scenario (%)

Reference Scenario 29,000 41,000 47,000 50,000 42,000 --

High Blade Failure Scenario 32,000 43,000 49,000 52,000 44,000 5%

High Gearbox Failure Scenario 31,000 43,000 48,000 52,000 43,000 3%

High Generator Failure Scenario 31,000 43,000 48,000 52,000 44,000 4%

100% Blade Failure Scenario 46,000 56,000 62,000 65,000 57,000 36%

100% Gearbox Failure Scenario 42,000 53,000 57,000 60,000 53,000 27%

100% Generator Failure Scenario 37,000 47,000 52,000 55,000 48,000 14%

Serial Blade Failure Scenario 69,000 60,000 47,000 50,000 56,000 34%

Serial Gearbox Failure Scenario 57,000 55,000 47,000 50,000 52,000 24%

Serial Generator Failure Scenario 43,000 48,000 47,000 50,000 48,000 13%

Note that costs are rounded to the nearest $1000 including the 20 year average; in some cases, the same 20 year average shows a 

slightly different percent deviation from the Reference Scenario due to minor differences in the underlying costs before rounding. 
7 

A full listing of all modeling results is in Appendix B. 

Figure 3-2. Scenario Results 

Note that the High Failure Rate Scenario (left column), 100% Replacement Scenario (center column), and the Serial 

Failure Scenario (right column) are shown for three component types: blades (top row), gearboxes (center row), and 

generators (bottom row). All cases include high/low uncertainties (dashed lines) based on the 30% increase/decrease 

of underlying failure rates. Reference costs (grey lines) are shown for comparison and are identical in each plot.
8 

Comparing across scenarios (i.e., columns in Figure 3-2), there is only a minor difference between 

the High Failure Scenarios and the Reference Scenario, while the 100% Replacement Scenarios 

and the Serial Failure Scenarios illustrate significant differences from the Reference Scenario. 

When compared to the 100% Failure Rate Scenario, the Serial Defect Scenario for each 

component shows slightly lower 20 year average costs. This is primarily driven by the 

significantly discounted crane costs in the Serial Defect Scenarios as compared to the 100% 

Failure Rate Scenarios.

The evolution of these costs over time is quite different between the 100% Replacement Scenarios, 

in which replacements are spread evenly across 20 years, and the Serial Failure Scenarios, in which 

replacements are concentrated in years 4 to 6. In the 100% Replacement Scenarios, costs increases 

from major component failures are incurred over all 20 years. In the Serial Failures Scenarios, the 

average O&M costs increases primarily in years 1 to 5 and years 6 to 10. 

The shape of the cost distribution changes slightly depending on the component selected. For 

example, in the Serial Failure Scenario, the cost of blades sharply decreases in per turbine O&M 

cost from the first five years to the last five years. The 200 blades replaced in years 4 and 5 

increases the average in years 1 to 5. The 100 blades replaced in year 6 increases the average for 

years 6 to 10, but replacements are lower than in the first five years. No blades were replaced in 

years 11 to 20, resulting in significantly lower costs relative to the first 10 years. By comparison, 

the Gearbox and Generator Serial Failure Scenarios show much shallower declines in O&M costs 

over the first 15 years. Replacing a set of blades is more expensive than replacing a single gearbox

or generator and the default generator failure rate (10%) is higher than the default blade failure rate

(5%). 

There are only minor differences between the Reference Scenario and the High Failure Scenarios 

for each of the three components (on average less than 5% over 20 years). For the 100% 

Replacement Scenarios and Serial Failure Scenarios, the largest cost differences relative to the 

Reference Scenario are for blades, followed by gearboxes, followed by a relatively smaller 

difference for generators. Several factors contribute to the blade’s higher O&M costs relative to 

the gearbox and generator. The modeled project has 300 blades, as compared to 100 gearboxes and 

100 generators. A set of three blades costs more than a single gearbox or generator. This accounts 

for a significant portion of the higher O&M cost. Also, this scenario assumes the blades must be 

purchased new, and therefore, does not consider any savings associated with using refurbished 

components or possible discounts for buying multiple blade sets. 

4 2010 COMPONENT COST UPDATE

DNV compiled annual component cost data in the form of price lists, from the years 2005 

through 2010, from the leading turbine manufacturers in the U.S. market. DNV updated the 

component cost data to capture some of the changes in wind project costs since the original 

O&M Model Report was published in early 2008 [1]. These data, from O&M replacement part 

price lists, are used with the permission of the turbine operators. Due to confidentiality 

agreements with price list contributors, individual owners of the manufacturers' price lists are not 

disclosed. However, the component cost data analyzed in this report are representative of close to
9 

90% of U.S. wind turbines installed in 2010 [2]. Wind turbine manufacturers' U.S. market share 

in 2010 is shown in Figure 4-1. 

GE Wind

43%

Vestas

17%

Siemens

13%

Mitsubishi

10%

Gamesa

6%

Suzlon 

Group

6%

Nordex

3% Others

2%

2010 United States Market Share

% of 6,334 MW Total Installed

Figure 4-1. Wind Turbine Manufacturers’ Share of 2010 U.S. Wind Power Installations

 Source: U.S. Wind Industry Annual Market Report Year Ending 2010 [2] 

Using these replacement costs as data inputs, turbine characteristics, and the year when the 

pricelists were issued, DNV calculated average turbine component costs, component cost ranges, 

estimated labor costs, and crane costs. 

The data are sorted into two main categories based on turbine rating: 

• Wind turbine rating of 1.5 - 2.0 MW 

• Wind turbine rating of 2.1 - 3.0 MW 

The resulting component, labor, and crane costs were used to update the inputs to the O&M Cost 

Model. The same list of components that were part of the original O&M Cost Model were 

populated with updated inputs to generate 2010 cost values for the scenarios discussed earlier in 

this report. It is important to note that, due to the nature of the model and the use of replacement 

parts price lists, the component cost values should not be interpreted as a bottom up calculation 

of the initial capital cost of a wind turbine. 

4.1 Component Costs – Methods and Assumptions

As shown in Table 4-1, the various replacement parts are categorized as the rotor, drive train, 

gearbox and lubrication, generator and cooling, brakes and hydraulics, yaw system, control 

system, electrical and grid, or miscellaneous. These categories are exclusive of consumables. 

Replacement parts (including mechanical, electrical, and hydraulic components) are those that 

wear or deteriorate during normal use. For example, gearboxes are a mechanical wear item, but 
10 

the main shaft and bedplate are not. 

Table 4-1. Parts Categories by System

Rotor Blades, pitch bearings, pitch actuators 

Drive train Main bearing, seals, couplings

Gearbox and lubrication Gearbox, lube pump, cooling system

Generator and cooling Generator, power converter, cooling system

Brakes and hydraulics Hydraulics, calipers, shoes

Yaw system Calipers, wear pads

Control system CPU, interface modules, sensors

Electrical and grid Contactors, circuit breakers, relays, capacitors 

Miscellaneous

Hardware, other small mechanical, 

hydraulic and electrical parts not identified

specifically

The components included in the generic configuration represent the current state of the art for 

modern turbines currently being supplied. The assumptions for each component category are 

described below.

Rotor: The rotor is three-bladed and each blade has independent pitch. The pitch bearings are 

the rolling-element type, and are periodically lubricated with grease. The pitch mechanism 

may be one of two types: 1) a hydraulic pitch system, which includes a pitch cylinder, 

proportional valve, crank arm mechanism, accumulator, and displacement transducer for 

each blade; or (2) an electric pitch system, which includes a motor with a position encoder, 

gear reducer, electronic drive, and backup battery bank for each blade. The pump and 

position controller are common for all three mechanisms (i.e., one per blade).

Drive train: The drive train consists of a main shaft supported by two main bearings, coupled to 

the gearbox using a hydraulic shrink coupling. A composite tube, with flexure connections, is 

used to couple the gearbox to the generator. 

Gearbox and lubrication: The gearbox is a combination planetary/helical unit, with an 

integral lubrication system and fluid cooler system. The gearbox is suspended from the 

bedplate with elastomeric bushings.

Generator and cooling: The generator is a single-speed, induction type. The variable-speed 

machine includes a wound rotor and slip-rings. Cooling is provided by an integral forced-air 

system.

Brakes and hydraulics: The brake is a caliper-type system located on the high-speed shaft of 

the gearbox. A dedicated hydraulic system provides pressure for the calipers. The brake is used 

only for parking, since the primary rotor brake is the blade pitch system.
11 

Yaw system: The yaw bearing is a sliding-bearing type, with spring-applied calipers for 

stabilization. The surfaces are periodically lubricated with grease. The yaw drives are electricmotor driven in a multiple-reduction gearbox. The number and size of the yaw drives increases 

with turbine size.

Control system: The control and monitoring system consists of a main controller in the 

turbine base, a remote controller in the nacelle, and another in the hub. The base unit contains a 

user interface and display. Control sensors include wind measurement instruments, rotor speed 

control, and power/grid monitoring transducers. Sensors specific to monitoring component 

condition are included in that category.

Electrical and grid: The turbine switchgear consists of a main breaker/disconnect, a line 

contactor for the generator power, and smaller contactors and circuit breakers for ancillary 

systems and power factor correction capacitors. A soft-starter is included for connecting to the 

grid for constant-speed machines.

Miscellaneous: This category includes a value for miscellaneous parts not specifically 

identified elsewhere, such as hardware, small hydraulics, and small electrics. 

Parts costs for each of the generic turbine sizes were estimated from machine cost data. In some 

cases, these data were drawn from manufacturers’ price lists; in other cases, they were derived

from actual receipts. The former data set is subject to an indeterminate mark-up; the latter may 

reflect a limited scope of supply. 

In addition to the component categories above, the O&M Cost Model includes a labor cost 

category. It includes the staff dedicated to turbine maintenance including regularly scheduled, 

unscheduled, and major maintenance. The calculation assumes the hourly rates for site staff 

show in Table 4-2. These are representative of rates at operating projects. Technician rates 

usually vary by skill level and experience, and often a crew consists of a senior-level technician 

paired with a junior-level technician. The rates represent average values for a crew. Local rates 

can vary by 25% and depend on the local labor market. The impact of labor rates on overall 

O&M costs is a function of the time required for repairs. 

Table 4-2. Annual Labor Rates

Category Base Burdened @ 35%

Junior Technician $31 $48

Senior Technician $49 $75

Source: DNV Update to Original O&M Cost Model [1] 

Typically, the lead time to procure the crane and the components is longer than the time it takes 

to install a new major component. Total return-to-service time can be significantly longer than 

the time required for labor for the repair. As examples, a blade, gearbox, or generator can be 

replaced by experienced technicians in approximately 3-5 days, weather permitting, once the 
12 

crane has arrived on site. Smaller components typically can be replaced in a few hours. 

Downtime for these components can be minimized by maintaining a good spare parts inventory. 

Finally, the model assumes that the wind energy facility rents a crane for any major 

replacement, and that the replacements will occur on a per-unit basis. Crane rental costs are 

driven by crane capacity and mobilization time. Two common crane types—conventional 

crawler cranes and truck-mounted cranes—are appropriate for wind turbine component 

replacements. The cost for a crawler crane is driven by mobilization, as the crane and boom are 

shipped in pieces and require 10 to 20 truckloads, depending on height. Hydraulic truckmounted cranes use a telescopic boom and require only one to three additional loads for 

counterweights. They are significantly cheaper to mobilize, but generally cost more per hour. 

Conventional cranes are sometimes available in a truck-mounted version, but still require 

multiple loads for the lattice boom and jibs. 

4.2 Results: Component Cost

The results of the 2010 component cost data analysis are presented in Table 4-3 and 4-4. 

Average, maximum, and minimum costs are provided for each component, as well as the per 

event labor costs associated with the repair or replacement of the component, and the per event 

costs associated with crane mobilization and deployment (for components where crane use is 

required). Finally, the estimated total per event component replacement cost is provided; this is 

the combined average cost of the component, labor and, if applicable, crane costs. Amounts 

shown are rounded to represent reasonable levels of precision. In some cases, the rounded perevent totals do not equal the sum of the rounded parts, labor, and crane costs because the totals 

were rounded after summing the inputs. 

Major component cost data on the two categories discussed in this report, 1.5-2.0 MW and 2.1-

3.0 MW machines, are biased toward the predominant turbines in the U.S. market today. 

Typically, the cost of major components and mechanical equipment associated with them will 

scale up relative to size. In particular, crane costs are sensitive to hub height and component 

weight. However, the rotor diameter, the complexity of control systems, and the overall quality 

of components varies based on different manufacturers; thus, a linear cost relation cannot be 

established for all components. 

Where no price list data inputs were available, such as the cost of the gearbox high speed section 

for turbines in the 2.0 MW to 3.0 MW range, the space was left blank to avoid providing 

misleading information. 
13 

Table 4-3. 2010 Component Cost Data 1.5 MW – 2.0 MW

Rating

Configuration

System Component Average High Low Labor 

Cost

Crane

Cost

Estimated

Total

Rotor Blade--struct. repair $88,000 $109,000 $57,000 $23,000 $44,000 $154,000

Blade--nonstruct. repair $13,000 $19,000 $6,000 $4,000 $23,000

Pitch cylinder & linkage $13,000 $23,000 $3,000 $1,000 $14,000

Pitch bearing $13,000 $15,000 $11,000 $4,000 $44,000 $61,000

Pump & hydraulics $3,000 $4,000 $3,000 $1,000 $4,000

Pitch position xdcr $2,000 $3,000 $1,000 <$500 $2,000

Pitch motor $8,000 $14,000 $2,000 <$500 $9,000

Pitch gear $7,000 $15,000 $3,000 $2,000 $9,000

Pitch controller $9,000 $10,000 $8,000 <$500 $9,000

Drive Train Main bearing $24,000 $38,000 $9,000 $13,000 $144,000 $181,000

High-speed coupling $7,000 $11,000 $5,000 $1,000 $8,000

Gearbox and Lube Gearbox--gears & brgs $221,000 $445,000 $180,000 $18,000 $144,000 $383,000

Gearbox--brgs, all $194,000 $215,000 $180,000 $8,000 $144,000 $347,000

Gearbox--high speed only $183,000 $187,000 $180,000 $3,000 $186,000

Lube pumps $2,000 $6,000 $1,000 <$500 $3,000

Cooling fan, gearbox cooling $2,000 $4,000 $1,000 <$500 $3,000

Generator and Cooling Generator--rot. & brgs $131,000 $412,000 $52,000 $6,000 $59,000 $195,000

Generator--brgs only $2,000 $4,000 <$500 $1,000 $3,000

Full converter $36,000 $47,000 $25,000 $2,000 $38,000

Motor, generator coolant fan $2,000 $4,000 $1,000 <$500 $2,000

Contactor, generator $13,000 $20,000 $2,000 <$500 $14,000

Partial converter (rotor side) $17,000 $18,000 $16,000 $1,000 $18,000

Brakes & Hydraulics Brake caliper $7,000 $9,000 $6,000 $1,000 $8,000

Brake Pads (set) $6,000 $9,000 $2,000 <$500 $6,000

Accumulator $2,000 $4,000 <$500 <$500 $2,000

Hydraulic pump $5,000 $12,000 $1,000 <$500 $5,000

Hydraulic valve <$500 $1,000 <$500 <$500 $1,000

Yaw System Yaw gear (drive+motor) $9,000 $17,000 $3,000 $1,000 $9,000

Yaw motor (with brake) $2,000 $4,000 <$500 <$500 $3,000

Yaw sliding pads $1,000 $1,000 <$500 <$500 $1,000

Yaw bearing (with gear) $31,000 $40,000 $22,000 $8,000 $144,000 $183,000

Yaw slew ring $199,000 $229,000 $169,000 $21,000 $144,000 $364,000

Control System Control board, top $11,000 $18,000 $6,000 <$500 $11,000

Control board, main $17,000 $20,000 $16,000 <$500 $17,000

Control module $6,000 $8,000 $5,000 <$500 $6,000

Sensor, static $1,000 $1,000 <$500 <$500 $1,000

Sensor, dynamic $3,000 $5,000 $3,000 <$500 $4,000

Electrical and Grid Main contactor $13,000 $13,000 $13,000 <$500 $13,000

Main circuit breaker $15,000 $24,000 $10,000 <$500 $16,000

Soft starter $1,000 $1,000 $1,000 $1,000 $2,000

Miscellaneous Miscellaneous parts $101,000 $131,000 $71,000 $101,000

1.5 MW - 2.0 MW

80 Meter Tower

 

Source: DNV Review of Replacement Part Price Lists
14 

Table 4-4. 2010 Component Cost Data 2.1 MW – 3.0 MW

Rating

Configuration

System Component Average High Low Labor 

Cost

Crane

Cost

Estimated

Total

Rotor Blade--struct. repair $223,000 $227,000 $218,000 $23,000 $72,000 $318,000

Blade--nonstruct. repair $12,000 $19,000 $6,000 $4,000 $16,000

Pitch cylinder & linkage $12,000 $21,000 $3,000 $1,000 $13,000

Pitch bearing $42,000 $54,000 $33,000 $4,000 $72,000 $118,000

Pump & hydraulics $9,000 $15,000 $2,000 $1,000 $10,000

Pitch position xdcr $1,000 $1,000 $1,000 <$500 $1,000

Pitch motor $11,000 $11,000 $11,000 <$500 $12,000

Pitch gear $5,000 $7,000 $4,000 $2,000 $7,000

Pitch controller $11,000 $14,000 $7,000 <$500 $11,000

Drive Train Main bearing $26,000 $34,000 $18,000 $13,000 $300,000 $339,000

High-speed coupling $11,000 $16,000 $4,000 $1,000 $12,000

Gearbox and Lube Gearbox--gears & brgs $445,000 $561,000 $405,000 $18,000 $300,000 $763,000

Gearbox--brgs, all $144,000 $187,000 $101,000 $8,000 $300,000 $452,000

Gearbox--high speed only

Lube pumps $4,000 $9,000 <$500 <$500 $4,000

Cooling fan, gearbox cooling $1,000 $1,000 $1,000 <$500 $1,000

Generator and Cooling Generator--rot. & brgs $145,000 $200,000 $117,000 $6,000 $107,000 $257,000

Generator--brgs only $3,000 $6,000 $1,000 $1,000 $4,000

Full converter $105,000 $141,000 $87,000 $1,000 $106,000

Motor, generator coolant fan $4,000 $5,000 $1,000 <$500 $4,000

Contactor, generator $3,000 $3,000 $2,000 <$500 $3,000

Partial converter (rotor side) $128,000 $166,000 $89,000 $1,000 $128,000

Brakes & Hydraulics Brake caliper $5,000 $8,000 $2,000 $1,000 $6,000

Brake Pads (set) $2,000 $3,000 $1,000 <$500 $2,000

Accumulator $3,000 $7,000 $1,000 <$500 $3,000

Hydraulic pump $6,000 $13,000 $2,000 <$500 $6,000

Hydraulic valve <$500 $1,000 <$500 <$500 $1,000

Yaw System Yaw gear (drive+motor) $7,000 $14,000 $4,000 $1,000 $7,000

Yaw motor (with brake) $3,000 $6,000 <$500 <$500 $3,000

Yaw sliding pads $1,000 $2,000 <$500 <$500 $2,000

Yaw bearing (with gear) $69,000 $89,000 $48,000 $8,000 $300,000 $377,000

Yaw slew ring

Control System Control board, top $8,000 $13,000 $3,000 <$500 $8,000

Control board, main $7,000 $13,000 $2,000 <$500 $7,000

Control module $2,000 $3,000 $1,000 <$500 $2,000

Sensor, static $1,000 $1,000 <$500 <$500 $1,000

Sensor, dynamic $2,000 $5,000 $1,000 <$500 $3,000

Electrical and Grid Main contactor $16,000 $21,000 $11,000 <$500 $16,000

Main circuit breaker $17,000 $31,000 $10,000 <$500 $18,000

Soft starter

Miscellaneous Miscellaneous parts $168,000 $219,000 $118,000 $168,000

2.1MW - 3.0 MW

90 Meter Tower

90 t t di t

Source: DNV Review of Replacement Part Price Lists
15 

4.3 O&M Arrangements 

The discussion above presents cost outputs for various component replacements that could be 

implemented under a range of O&M arrangements at any given wind energy project. Aspects

that vary by O&M arrangement (and may or may not affect actual O&M costs) include: 

Warranty Provisions: Warranty provisions affect who is responsible for replacement costs at a 

project. While specific warranty provisions vary, the original equipment manufacturer is 

typically responsible for replacing failed parts when failures occur during normal operations in

the warranty period. There are four primary warranty scenarios: 

1. A parts-only warranty is a warranty in which the OEM is only responsible for providing 

replacement parts; the owner is responsible for troubleshooting, labor, and significant 

additional expenses that can be incurred in the event a crane is required. 

2. A full parts warranty provides parts and "in and out" service. This typically covers all 

costs associated with removing and replacing the parts. 

3. A hybrid of these two options is a parts-only warranty with crane services. This is similar 

to the parts-only service except that any repairs that require a crane will be performed by 

the OEM. 

4. The final option is when the OEM provides all O&M services in addition to the warranty 

services. In this case, the OEM will provide all scheduled and unscheduled maintenance, 

including troubleshooting and repair. 

Regular maintenance: Typically, regular O&M consists of scheduled and unscheduled 

maintenance, including some provision for remote monitoring of the project. These services can 

be provided by the owner, the OEM, or a third-party operator. When provided by the OEM or a 

third-party operator, the contract may either cover only scheduled maintenance, with 

unscheduled maintenance provided on a time and materials basis, or the contract may include 

both scheduled and unscheduled maintenance for one fee. Parts may be included in the contract 

or they may be purchased by the owner for use by the operator. Some OEM contracts may 

include all parts and labor for a fixed fee, or charge an adjustable fee that is based on production. 

Maintenance reserves: In cases where the project company responsible for the maintenance 

costs has obtained project-level debt, the terms of the credit agreement often stipulate certain 

reserve mechanisms to manage unplanned future costs not directly included in the annual O&M 

budget. The amount reserved will depend on the project history to date, expected issues relevant 

to the project equipment, and known equipment issues industry-wide. In the absence of projectlevel debt, owners typically have some planned provision for these maintenance costs, but the 

mechanism or approach varies widely in such cases.

4.4 Component Cost 2005 – 2010 Historical Trend

Using a collection of manufacturers’ replacement part price lists, DNV analyzed main turbine 

component prices, when available, from 2005 through 2010, to determine historical cost trends. 

The analysis focused on the main turbine component prices, where they were available. Prices 

were selected from similar size turbines and equal capacity gearboxes, with comparable 
16 

configurations and/or components. These were used to generate the data inputs for the following 

major wind turbine component assemblies:

• Blades

• Gearbox 

• Generator

• Converter 

• Yaw Gears

It is important to note that the cost trends of these components were analyzed individually, and 

do not represent a complete system or other combination of components, nor are they meant to 

reflect the historic cost trend of new wind turbines. DNV currently has insufficient historical 

trend information on balance of plant, foundation, tower, transportation, and installation to 

provide an accurate analysis of historical costs. These costs were excluded from the 2010 

Component Cost section. 

Wind turbine component costs remained relatively stable between 2005 and 2010, as seen in 

Table 4-5 below. The table also shows the cumulative inflation rate for the individual 

components during the same time period, relative to 2005. 

Table 4-5. 2005 – 2010 Component Cost Trend

Component

Average

Annual Cost 

Increase (%)

Cumulative Inflation Relative to 2005 (%)

2005 2006 2007 2008 2009 2010

Blade 2.0 0 4 6 10

Gearbox 3.5 0 0 13 21 19

Generator -1.5 0 -11 -10 -7

Converter 2.3 0 0 0 4 12

Yaw Gear 3.2 0 0 4 17

The average annual cost increase rate for these turbine components during this period was 

approximately 2%. Gearboxes and yaw gears sustained annual inflation rates of 3.5% and 3.2%, 

respectively; blades and converters showed 2.0% to 2.3% annual inflation rates and generators 

experienced an annual deflation rate of -1.5%. The values in 2010 represent the cumulative 

inflation relative to 2005 as seen in Figure 4-2. 
17 

Cumulative Inflation Rate 2005 - 2010

-10%

-5%

0%

5%

10%

15%

20%

25%

Turbine Components

Compounded Variance

Blade Gearbox Generator Converter Yaw Gear

Figure 4-2. Cumulative Inflation Rate 2005 – 2010

5 PROJECT FINANCING

This section provides a high-level description of representative financing structures in 2010 and 

2011 and relevant metrics for utility-scale wind power projects. Included is a qualitative outline 

of general wind development market conditions, including financing structures, capital 

availability, sources of funds (debt versus equity), and other information. 

5.1 Financing Structures

Wind projects typically require higher capital costs and lower operating costs than fossil-fueled 

power plants. These result in the need for higher levels of capital earlier than for a similar-sized 

conventional power project. As a result of the high capital cost for commercial-scale wind 

energy projects, the wind industry may use any one of eight primary financing structures and 

leasing options to manage project risk. 

The eight structures range in complexity and involve varying combinations of cash and tax 

equity capital from project developers and institutional investors, as well as commercial debt. 

These structures, outlined below, consider the differing financial capacities and business 

objectives of wind project developers, and the varying investment risk tolerances and objectives 

of the tax-oriented investors and debt providers. 

The descriptions of the structures below are based on the report, Wind Project Financing 

Structures: A Review & Comparative Analysis, by Harper et al. [3]. DNV has updated the 

prevalence of the various structures based on our knowledge of 2010 and 2011 market activities, 

when possible.

Corporate Equity: In this structure, a single developer/investor (parent), with significant 

financial strength, will establish a special purpose entity to hold the assets of the project. Capital 
18 

initially generated from other projects and activities is used to fund the project. The project’s net 

cash flow and tax benefits flow back to the parent. While the parent performs sole management 

duties, other entities may take part in the day-to-day operational and maintenance 

responsibilities. [3] 

The Corporate Equity Structure is the simplest financing arrangement considered here, and is 

prevalent among larger developers and utilities that have the capacity to self finance. All 

financial and management issues are solved in-house, without requiring the approval of outside 

investors and all benefits flow directly to the parent. The parent may gain competitive advantage 

due to the flexibility and time-efficiencies inherent to this structure [3]; however, there are 

relatively few organizations active in the wind industry in 2011 with the capital resources to 

adopt this approach. 

Strategic Investor Flip: In the Strategic Investor Flip structure, an investor (known as a tax 

investor) interested in playing an active role in wind projects will negotiate a percentage 

ownership share with a project developer. This structure is similar to traditional joint ventures, 

but with three differentiating characteristics. [3] 

First, in the Strategic Investor Flip structure, the tax investor provides almost all of the project 

equity and, in return, is allotted almost all of the distributable cash and tax benefits. For example, 

a tax investor may provide an undercapitalized developer with 99% of the project’s total cost, 

leaving just 1% to be funded by the developer. In some cases, a tax investor has provided as 

much as 99.9% of the total project’s costs. [3] 

Second, at a point in time known as the flip point, the tax benefits and cash flow change typically

in favor of the developer. The flip point occurs when a pre-negotiated internal rate of return 

(IRR) is met by the investor. It is often projected to be reached shortly after the tenth anniversary 

of the project’s commercial operation date, coinciding with the expiration of production tax 

credits (PTC) for the project. This strategy is favored by developers who are unable to efficiently 

use tax benefits. It is even possible to incorporate a second flip point, having the inversion of 

percentage allocations staged across two flip points. [3]

Third, there is often an option included in the financial structure that allows the developer to 

purchase the tax investor’s ownership share after the flip point. By this time, tax benefits have 

been realized by the tax investor and the investment is recorded as a true equity investment. [3] 

The Strategic Investor Flip is less common today. This structure attracts third-parties who have 

equity to initiate projects to capture tax benefits, while allowing developers to retain some 

financial interest in the project.

Institutional Investor Flip: Similar to the Strategic Investor Flip structure, the Institutional 

Investor Flip structure has developers bring in a separate tax investor who receives the project’s 

tax benefits. There is a flip point when the allocation of cash and tax benefits change. But there 

are important differences between these two flip structures. [3] 
19 

First, the Institutional Investor Flip structure tends to attract equity from more passive 

institutional investors that are not actively involved in the wind project. Second, the cash and tax 

benefit percentages received by the investor do not equal their initial investment percentage. This 

allows developers, who have a greater portion of initial equity capital invested in the project, to 

receive distributable cash from the project until they recover their investment, minus any tax 

benefits (which go to the institutional investor). The developer may receive what they have 

invested in the project, but not any returns on their investment, usually for the first four to six 

years of commercial operation. Once the developer has received 100% of their initial investment, 

100% of the distributable cash plus tax benefits are allocated to the institutional investor until the 

flip point is reached. [3]

Under the Institutional Investor Flip structure, the developer maintains management control over 

project operations, but the institutional investor has voting rights and veto power on major 

decisions. Developers who have capital to invest, but lack the ability to use tax benefits, find this 

structure appealing. Investors who want developers more vested in the success of the project also 

find this structure appealing. [3] This structure was popular for most of the 2000s. Repeated use 

has made investors comfortable with the structure and has brought improved standardization of 

transaction documentation. 

Pay-As-You-Go (PAYGO): Structurally, PAYGO is based on the Strategic Investor Flip, but 

with significant differences. Under PAYGO, the developer contributes roughly half of the initial 

capital required for the project, but the pre-“flip” cash and tax benefits do not match the 

percentage of equity contributions. In addition to their initial investment obligation, the tax 

investor makes annual payments based on the value of PTCs, allowing them to defer a portion of 

their equity investment over time. [3] 

PAYGO is typically used as a refinancing strategy by developers who are also major investors. 

This structure allows developers to reduce their investment stake in projects or raise capital for 

other corporate purposes. Additionally, developers with capital to invest can maintain an 

ownership stake in projects for a longer term than some of the previous structures. Investors 

lacking a tax appetite and, when unsure about PTCs, they tend to choose PAYGO to acquire 

existing wind project assets and tap tax investor capital to finance a portion of the acquisition 

costs. PAYGO allows tax investors to offset some of the risk associated with potentially lowerthan-expected wind resource, new turbine technologies, and other project risks. [3] 

Cash Leveraged: In the Cash Leveraged structure, project-level loans are sized to be repaid 

from the cash flow generated by the project and secured by the project’s assets. Initial funding 

contributions by investors and developers are similar to those in the Strategic Investor structure, 

but the amount of initial equity capital required is reduced based on the amount of debt incurred. 

As a result, loan principal and interest payments decrease the amount of distributable cash 

available to the project’s investors. Debt can vary based on project requirements, but it is 

typically 40-60% of the total project costs. [3]

By seeking limited recourse project debt, equity returns can increase and required equity 

contributions can decrease. By adding debt to the project, equity returns go up because debt is 

usually cheaper than equity. In general, investors are not comfortable contending with a lender 
20 

when the project encounters financial stress or if the project experiences foreclosure. As a result, 

more passive investors, like institutional investors not strategic investors, are usually sought out 

for this type of financial structure. The use of Cash Leveraged structures has increased 

significantly in 2010 and 2011 with the availability of the cash grant form of the Investment Tax 

Credit (ITC). 

Cash and PTC Leveraged: The cash and PTC-leveraged structure adds an additional layer of 

debt based on the expected PTC at the project level, and lasts the full term of the PTC loan – ten 

years. Both PTC-based and cash-based loans are secured by project assets and assignments of 

contract rights. PTCs are used as a tax credit for project owners and do not generate cash that is 

used to repay project-level debt. As a result, additional debt may negatively impact (possibly 

exceed) cash flow created by the debt service coverage ratio for the cash-based loan. 

Consequently, tax investors usually need to commit periodic additional equity investments into 

the project to address lender concerns. This is capped at the amount the PTC generated during 

that same period. [3] 

The same rationale for using debt to finance projects can be applied in this case. Lower costs 

associated with debt capital increase project equity returns while requiring less up-front 

investment. Developers favoring this structure are comfortable using debt to leverage their equity 

investment and believe the increase in IRR from incremental PTC debt justifies the added 

complexity. Maintaining control of projects also is attractive to developers and they usually 

already have experience in debt financing. By including the PTC, the number of tax investors 

may be limited because investors have to be willing to assume a contingent obligation around 

future capital contributions. [3] 

Due to the uncertainty associated with the future cost of capital for up to ten years, and the 

increased risk presented by a senior debt’s priority in receiving payments from the project, tax 

investors have been reluctant to participate in the Cash and PTC Leveraged structure and 

generally charge an associated premium when debt is used at the project level. 

Back Leveraged: Similar to the Institutional Flip structure, the Back Leveraged structure adds a 

layer of debt for the developer outside of the project, specifically at the holding company level. 

The developer initially shows interest in the project by acquiring debt to fund capital 

contributions. The debt provider can impact returns at the developer level, demanding a pledge 

of the developer’s equity interests, but the creditor has no recourse to the project company. 

Therefore, this structure does not affect project-level economics. The underlying allocations and 

structure remain the same as in the Institutional Investor Flip structure; however, loan terms are 

typically shorter (e.g., five years). [3] 

The developer can increase IRR by securing lower cost capital to fund initial contributions under 

this structure. It also can increase an undercapitalized developer’s equity participation. Since the 

financing is done at the developer level, tax investors are not impacted by this type of financial 

structure. The back leveraged structure is becoming more common because 1) it allows 

developers to increase their returns from projects through the use of leverage, and 2) tax 

investors are not exposed to project-level debt. [3] 
21 

Sale-Leaseback: The Sale-Leaseback is a recent innovation in wind project financing [4]. It

became more viable when the PTCs were supplemented with the ITCs and cash grants; both can 

be used by a non-operating owner. The Sale-Leaseback provides benefits unavailable in the other 

structures and allows the borrower to obtain 100% financing. Equity investors have a starting tax 

basis equal to the acquisition price of the project, which can be beneficial in calculating tax 

benefits, including incentives and depreciation. 

The Sale-Leaseback structure can provide access to capital from bank leasing companies, which 

may be unavailable in an Investor Flip structure. Either the lessee or the lessor has the option to 

apply for the grant. The lessee can apply for, and be the recipient of, the grant; the lessee places 

the property in service, sells the property to the lessor, and leases it back within three months of 

the project being placed in service. 

5.2 Capital Availability and Cost of Capital

According to several discussions with equipment manufacturers, developers, and representatives 

of finance institutions, availability of project financing was one of the significant limiting factors 

in the U.S. wind energy market in 2009 and early in 2010, but the situation has since rebounded 

significantly. The primary reason for project financing limitations was the economic downturn 

that hit the U.S. and global economies in the fall of 2008, and led to a tightening of the financial 

markets. 

The global credit crisis negatively affected wind project financing in two important ways: 

• Project-level debt – In the aftermath of the credit crisis, lenders were sizing debt on 

more stringent terms compared to pre-crisis conditions. This resulted in increased 

borrowing costs and an overall reduction in the level of lending for new projects in 2009 

and early 2010. The availability of project-level debt has since rebounded significantly. 

• Tax equity – Historically, most projects relied largely on tax equity investment for 

project financing. The number of tax equity participants and the associated availability of 

tax equity were significantly reduced due to commensurate reductions in corporate profits 

and the resulting tax appetite. About 20 investors were active in the renewable energy tax 

equity market before the crisis, but this was reduced to a handful of organizations by the 

end of 2008. The number of investors active in the market rebounded, but as of 2010, it 

was still below the pre-crisis level at about 16 tax equity investors. All were not active in 

the U.S. wind market [5]. The need for tax equity was decreased by the use of the cash 

grant program instead of the ITC and PTC programs. 

In an effort to counteract the impact of the global credit crisis on the wind industry, provisions 

were included in the American Reinvestment and Recovery Act (ARRA) passed in February 

2009. This included the aforementioned cash grant in lieu of the ITC. This incentive provided 

financing for projects that otherwise would have had difficulty monetizing the tax benefits 

associated with the PTC or ITC due to the limited availability of tax appetite. The U.S. Treasury 

disbursed $1.4 billion in 2009 and $3.5 billion in 2010 to wind projects under this program [6]. 

Prior to the global credit crisis, the cost of project-level debt was trending upward. During this 

period, commonly referenced benchmark rates were relatively high, while bank margins were 
22 

relatively low, ranging from about 125 to 175 basis points. As a result of the credit crisis, base 

rates dropped significantly, but margins increased to about 325 to 375 basis points. The 

combined result is that the overall interest rates for project-level debt have remained fairly steady 

in 2010 and 2011, with perhaps a slight reduction in interest rates relative to pre-crisis levels. 

Bank margins have come down recently from around 275 to 300 basis points. [7] 

5.3 Empirical Findings on Financial Metrics

DNV conducted empirical research on various financial metrics including the following standard 

financial metrics: 

• Cost of standard equity – defined as the 20 year after-tax internal rate of return (IRR) for 

the primary project owner. 

• Cost of tax equity – defined as the 20 year after-tax IRR for a tax equity owner. In 

projects with a flip structure, this includes both pre- and post-flip cash flows.

• Cost of debt – defined as the before-tax all-in annual interest rate for a term loan. This 

does not include construction loans, which are typically short-term instruments.

• Debt fraction – defined as the percentage of the overall project cost that is funded by a 

term loan. This does not include any construction loan.

• Debt tenor – defined as the length of the term loan in years. 

• Debt service coverage ratio (DSCR) – defined as the coverage ratio for sizing debt using 

a P50 production case. In practice, most term loans are also sized on the one year P99 

production case, with a DSCR of 1.0. Lenders may offer the smaller of the loan sizes 

between the two cases. [8]

DNV reviewed project-level pro formas for 15 projects developed in 2010 and 2011. Most of 

these projects were funded using the cash-grant version of the ITC. DNV reviewed recent public 

presentations and reports from debt and equity institutions to gather information on target rates 

of return. DNV also interviewed six project participants, between June 2011 and July 2011, 

including project lenders, sponsors, and equity investors to discuss our empirical findings. The 

results below reflect both the empirical data from the evaluated pro formas and the results of 

interviews with project participants. Where appropriate, a range of results is presented. 

However, individual projects may vary materially from the ranges indicated below. 

The cost of standard equity ranged from 8% to 13%, with a baseline of 10%. This was lower if 

an equity holder were buying into an equity stake in an operating portfolio as compared to earlystage, non-operating development portfolio. 

The cost of tax equity ranged between 7% and 15%, with a baseline of 9% or 12% depending on 

the presence or absence of senior debt (e.g., a term loan). There were relatively fewer tax equity 

deals in years when the cash grant was in place. There was a premium of approximately 300 

basis points (3%) on the cost of tax equity, if the project had senior term debt. This market was 

much more variable and project-specific than the debt market and was influenced by dynamics in 

the affordable housing market, which competes with renewable energy projects for tax equity 
23 

investment funding. DNV’s review of this metric relied more heavily on discussion with industry 

partners than our review of the debt-related metrics. 

The cost of debt ranged between 6.75% and 8%, with a baseline of 7.125%. The typical bank 

margin over LIBOR was approximately 225-325 basis points. In 2010 and 2011, many term 

loans were fully amortized over longer periods (e.g., 15-18 years) as opposed to mini-perm 

structures that included a large balloon payment after 5 to 7 years. Mini-perm structures were 

more common in late 2008 and 2009 following the financial crisis of 2008. Other findings 

included the following: 

• The debt fraction ranged between 40% and 55%, with a baseline of 45%, though some 

isolated cases were identified outside this range, 

• The debt tenor ranged from 15 to 18 years, with a baseline of 17 years, though some 

isolated cases were identified outside this range, and 

• The base case DSCR ranged from 1.4 to 1.55, with a baseline of 1.45. 

Overall, the debt market appeared to be more consistent across projects than the tax equity 

market, which had more project-specific details. Our investigation converged quickly on the debt 

numbers and there were fewer comments on these in our discussions with industry partners. 
24 

6 REFERENCES 

[1] Poore, R. Development of an Operations and Maintenance Cost Model to Identify Cost of 

Energy Savings for Low Wind Speed Turbines: July 2, 2004 -- June 30, 2008. NREL/SR-500-

40581. Work performed by Global Energy Concepts, LLC, Seattle, Washington, Golden, CO: 

National Renewable Energy Laboratory, January 2008. 

http://www.nrel.gov/docs/fy08osti/40581.pdf

[2] American Wind Energy Association. U.S. Wind Industry Annual Market Report Year Ending 

2010. Washington D.C., 2011. http://www.awea.org/learnabout/publications/reports/AWEA-USWind-Industry-Market-Reports.cfm

[3] Harper, J.; Karcher, M.; Bolinger, M. Wind Project Financing Structures: A Review & 

Comparative Analysis. LBNL-63434. Berkeley, CA: Lawrence Berkeley National Laboratory, 

September 2007. http://eetd.lbl.gov/ea/emp/reports/63434.pdf

[4] Bolinger, M. Community Wind: Once Again Pushing the Envelope of Project Finance. 

LBNL-4193E. Berkeley, CA: Lawrence Berkeley National Laboratory, January 2011. 

http://eetd.lbl.gov/ea/emp/reports/lbnl-4193e.pdf

[5] Partnership for Renewable Energy Finance. Prospective 2010-2012 Tax Market 

Observations, 2010. http://uspref.org/white-papers

[6] “Section 1603: List of Awards.” Microsoft Excel file, U.S. Department of Treasury.

http://www.treasury.gov/initiatives/recovery/Documents/Web Posting.xlsx

[7] GlobalData. Project Finance Trends in the Global Wind Energy Market to 2015 - Deals, 

Competitive Analysis of Debt Providers, Advisors, Sponsors and Interest Rates, August 2010. 

[8] Lowder, T. P50? P90? Exceedance Probabilities Demystified. Renewable Energy Project 

Finance. Golden, CO: National Renewable Energy Laboratory, October 2011. 

https://financere.nrel.gov/finance/content/p50-p90-exceedance-probabilities-demystified. 
A-1 

APPENDIX A – FAILURE RATE AND PARTS COST ASSUMPTIONS

Table A-1. Reference Scenario Failure Rates and Part Cost Assumptions

System Component 

Failure 

Prediction 

Failures per 

100 parts by 

Year 20

Weibull 

Curve 

Parameter – 

Alpha 

Weibull 

Curve 

Parameter – 

Beta

Parts per 

Turbine 

Parts Cost 

($) Crane? 

Parts in 

Project 

Failures in 

20 Years 

Rotor

 Blade-struct. Repair Constant Rate 5.0 3 87,500 YES 300 15 

 Blade-nonstruct. Repair Constant Rate 20.0 3 3,000 NO 300 60 

 Pitch cylinder & linkage Weibull Curve 10.0 3.5 3 3,800 NO 300 547 

 Pitch bearing Weibull Curve 50.0 3.5 3 13,100 YES 300 13 

 Pump & hydraulics Weibull Curve 12.0 3.5 1 2,200 NO 100 142 

 Pitch position xdcr Weibull Curve 12.0 2.0 3 1,800 NO 300 468 

 Pitch motor Weibull Curve 15.0 1.1 0 8,400 NO 0 

 Pitch gear Weibull Curve 12.0 3.5 0 4,600 NO 0 

Drive Train

 Main bearing Weibull Curve 39.0 3.5 1 24,400 YES 100 10 

High-speed coupling Weibull Curve 25.0 3.5 1 6,700 NO 100 39 

Gearbox and Lube

 Gearbox-gears & bearings Constant Rate 5.0 1 154,700 YES 100 5 

 Gearbox-bearings, all Constant Rate 5.0 26.0 3.5 1 800 YES 100 35 

 Gearbox-high speed only Weibull Curve 26.0 3.5 1 36,700 NO 100 35 

 Lube pumps Weibull Curve 12.0 3.0 2 2,400 NO 200 294 

Gearbox cool. fan motor Weibull Curve 19.0 1.1 2 2,000 NO 500 195 

Generator and Cooling

 

Generator-rotor & 

bearings Constant Rate 10.0 1 91,600 YES 100 10 

 Generator--bearings only Weibull Curve 17.0 3.5 2 2,100 NO 200 184 

 Full converter Weibull Curve 15.0 2.0 1 9,500 NO 100 117 

 Gener. cooling fan motor Weibull Curve 19.0 1.1 1 1,600 NO 100 98 

 Contactor, generator Weibull Curve 20.0 2.0 3 13,500 NO 300 235 

Partial converter Weibull Curve 15.0 2.0 0 2,600 NO - - 
A-2 

System Component 

Failure 

Prediction 

Failures per 

100 parts by 

Year 20

Weibull 

Curve 

Parameter – 

Alpha 

Weibull 

Curve 

Parameter – 

Beta

Parts per 

Turbine 

Parts Cost 

($) Crane? 

Parts in 

Project 

Failures in 

20 Years 

Brakes and Hydraulics

 Brake caliper Weibull Curve 10.0 2.0 1 700 NO 100 194 

 Brake pads Constant Rate 200.0 10.0 2.0 1 5,900 NO 100 200 

 Accumulator Weibull Curve 6.0 3.0 4 1,500 NO 400 1,356 

 Hydraulic pump Weibull Curve 12.0 3.0 1 4,900 NO 100 146 

Yaw System

 Yaw gear (drive+motor) Constant Rate 5.0 4 6,000 NO 400 20 

 Yaw motor (with brake) Weibull Curve 10.0 2.0 4 2,400 NO 400 776 

 Yaw sliding pads Weibull Curve 10.0 3.5 8 800 NO 800 1,462 

Control System

 Control board, top Weibull Curve 15.0 2.0 1 5,500 NO 100 117 

 Control board, main Weibull Curve 15.0 2.0 1 8,600 NO 100 117 

 Control module Weibull Curve 15.0 2.0 13 6,100 NO 1300 1526 

 Sensor, static Weibull Curve 14.0 2.0 17 500 NO 1700 2184 

Electrical and Grid

 Main contactor Weibull Curve 20.0 2.0 1 9,200 NO 100 77 

 Main circuit breaker Weibull Curve 30.0 2.0 1 10,800 NO 100 7737 

Soft starter Weibull Curve 30.0 2.0 0 700 NO - - 

Misc. (All others)

Miscellaneous parts Constant Rate 5.0 1 100,900 NO 100 5 
B-1

APPENDIX B – SCENARIO RESULTS

Table B-1. All Scenario Model Results – O&M Costs by Project Operating Year

O&M Cost by Project Operating Year ($/turbine/year)

Year 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 

Reference 

Scenario 24,300 26,300 28,900 31,300 34,200 36,500 38,900 41,000 42,700 44,600 46,200 47,300 47,400 47,700 48,500 49,000 49,700 50,900 51,300 51,300 

High Failure 

Rate Scenario 

– Blades 

26,900 29,000 31,600 34,000 36,800 39,200 41,500 43,700 45,400 46,300 47,700 47,900 48,300 49,300 49,400 50,600 51,300 51,900 52,400 52,900 

High Failure 

Rate Scenario 

– Generator

26,400 28,500 31,000 33,400 36,300 38,700 41,000 43,100 44,800 46,800 47,200 48,200 48,400 48,700 49,500 50,100 50,800 51,900 52,400 52,400 

High Failure 

Rate Scenario 

– Gearbox 

26,000 28,000 30,600 33,000 35,900 38,300 40,600 42,700 44,400 46,400 47,900 47,900 48,100 49,200 49,200 50,400 51,000 51,600 52,100 52,600 

100% 

Replacement 

Scenario – 

Blades

41,200 43,300 45,800 48,200 50,800 53,100 54,900 56,700 58,100 59,400 60,400 60,900 61,500 62,100 62,400 63,300 64,100 64,800 65,600 65,800 

100% 

Replacement 

Scenario – 

Gearboxes

37,900 40,000 42,500 44,900 46,800 49,200 51,300 53,200 54,100 55,700 56,300 57,100 57,300 57,700 58,300 58,900 59,600 60,600 61,100 61,200 

100% 

Replacement 

Scenario – 

Generators 

32,000 34,000 36,600 39,000 41,700 43,400 45,600 47,500 49,100 50,200 51,400 51,700 52,000 52,900 53,100 54,200 54,900 55,500 56,100 56,500 

Serial 

Replacement 

Scenario – 

Blades 

22,900 25,000 27,600 132,900 135,700 138,100 37,500 39,600 41,300 43,300 44,800 46,000 47,200 47,300 47,400 48,600 49,200 49,800 50,800 50,800 

Serial 

Replacement –

Gearboxes

23,400 25,500 28,000 103,700 106,600 109,000 38,000 40,100 41,800 43,800 45,300 46,400 46,600 46,900 47,800 48,300 49,000 50,200 50,600 50,700 

Serial 

Replacement –

Generators 

23,200 25,200 27,800 73,500 76,300 78,700 37,800 39,900 41,600 43,600 45,100 46,200 46,400 47,600 47,600 48,900 49,500 50,000 50,500 51,000