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Development of An Operations and Maintenance Cost Model To Identify Cost of Energy Savings For Low Wind Speed Turbines

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A national laboratory of the U.S.

Department of Energy Office of Energy Efficiency & Renewable Energy

National Renewable Energy Laboratory


Innovation for Our Energy Future

Development of an Operations and Maintenance Cost Model to Identify Cost of Energy Savings for Low Wind Speed Turbines
July 20, 2004 June 30, 2008
R. Poore and C. Walford
Global Energy Concepts, LLC Seattle, Washington

Subcontract Report
NREL/SR-500-40581 January 2008

NREL is operated by Midwest Research Institute Battelle

Contract No. DE-AC36-99-GO10337

Development of an Operations and Maintenance Cost Model to Identify Cost of Energy Savings for Low Wind Speed Turbines
July 20, 2004 June 30, 2008
R. Poore and C. Walford
Global Energy Concepts, LLC Seattle, Washington NREL Technical Monitor: A. Laxson
Prepared under Subcontract No YAM-4-33200-07

Subcontract Report
NREL/SR-500-40581 January 2008

National Renewable Energy Laboratory


1617 Cole Boulevard, Golden, Colorado 80401-3393 303-275-3000 www.nrel.gov Operated for the U.S. Department of Energy Office of Energy Efficiency and Renewable Energy by Midwest Research Institute Battelle Contract No. DE-AC36-99-GO10337

NOTICE This report was prepared as an account of work sponsored by an agency of the United States government. Neither the United States government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States government or any agency thereof. Available electronically at http://www.osti.gov/bridge Available for a processing fee to U.S. Department of Energy and its contractors, in paper, from: U.S. Department of Energy Office of Scientific and Technical Information P.O. Box 62 Oak Ridge, TN 37831-0062 phone: 865.576.8401 fax: 865.576.5728 email: mailto:reports@adonis.osti.gov Available for sale to the public, in paper, from: U.S. Department of Commerce National Technical Information Service 5285 Port Royal Road Springfield, VA 22161 phone: 800.553.6847 fax: 703.605.6900 email: orders@ntis.fedworld.gov online ordering: http://www.ntis.gov/ordering.htm This publication received editorial review at NREL

Printed on paper containing at least 50% wastepaper, including 20% postconsumer waste

Table of Contents
1. 2. 3. 4. 5. Introduction ............................................................................................................................1 Scope ........................................................................................................................................3 Background .............................................................................................................................5 Source Data .............................................................................................................................6 Approach .................................................................................................................................7 5.1 Model Assumptions...........................................................................................................9 5.2 Facility Costs...................................................................................................................10 5.2.1 Operations and Administration ................................................................................10 5.2.2 Site Maintenance......................................................................................................10 5.2.3 Equipment and Supplies ..........................................................................................11 5.3 Turbine Costs ..................................................................................................................11 5.3.1 Labor ........................................................................................................................11 5.3.2 Parts..........................................................................................................................14 5.3.3 Consumables ............................................................................................................16 5.3.4 Failure Rates ............................................................................................................17 5.3.5 Time to Repair .........................................................................................................19 5.3.6 Cranes ......................................................................................................................20 6. 7. Results....................................................................................................................................24 Reducing O&M Costs ..........................................................................................................32 7.1 7.2 7.3 7.4 7.5 8. Assign Tasks to Outside Services ...................................................................................32 Condition Monitoring......................................................................................................32 After-Market Components ..............................................................................................32 Innovative Rigging and Tooling .....................................................................................32 Record Keeping...............................................................................................................33

Conclusions............................................................................................................................34

Appendix A Using the O&M Cost Estimator Spreadsheet Appendix B Part Quantities and Costs Appendix C Failure Rate Assumptions Appendix D Model Results

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List of Figures
Figure 1. Database Architecture ..................................................................................................... 7 Figure 2. O&M Costs on a per Turbine Basis ................................................................................ 9 Figure 3. Number of Turbines per Technician.............................................................................. 12 Figure 4. Annual Service Hours per Turbine................................................................................ 13 Figure 5. Representative Gearbox Weight.................................................................................... 21 Figure 6. Representative Generator Weight.................................................................................. 22 Figure 7. Crane Costs by Tonnage................................................................................................ 22 Figure 8. Cost per Turbine ($), 20-Year Project Life ................................................................... 24 Figure 9. O&M Costs per Turbine, 5-Year Averages................................................................... 25 Figure 10. Annual Turbine O&M Costs ....................................................................................... 26 Figure 11. Crane Costs.................................................................................................................. 26 Figure 12. Parts Costs over 20 years, by System .......................................................................... 27 Figure 13. Failure Distribution over 20 years, Major Parts .......................................................... 27 Figure 14. Average Cost per kW, 60 MW Project........................................................................ 28 Figure 15. Average Cost per kWh, 60 MW Project...................................................................... 29 Figure 16. Annual Project Cost..................................................................................................... 29 Figure 17. Annual Failures of 2.5 MW Major Components, 60 MW Project Size ...................... 30 Figure 18. Estimated O&M Costs for 2.5 MW Turbines on 80-m v. 100-m Towers................... 30 Figure 19. Effect of Internal Crane on O&M Costs...................................................................... 31

List of Tables
Table 1. Typical Turbine Rating/Tower Combinations.................................................................. 8 Table 2. Cost Contributor Categories ............................................................................................. 9 Table 3. Manpower Levels by Number of Turbines..................................................................... 10 Table 4. Representative Yearly Site Maintenance Expenditures.................................................. 11 Table 5. Representative Yearly Expenditures for Equipment and Supplies................................. 11 Table 6. Labor Hours per Turbine per Technician by Year.......................................................... 13 Table 7. Annual Labor Rates ........................................................................................................ 14 Table 8. Parts Categories by System............................................................................................. 15 Table 9. Per-Turbine Annual Consumable Cost Estimates, $ ...................................................... 17 Table 10. Estimates of Failure Rate Mean Life ............................................................................ 18 Table 11. Assumed Repair Time (Manhours)............................................................................... 20 Table 12. Gearbox & Main Bearing R&R Crane Assumptions.................................................... 23 Table 13. Blade and Pitch Bearing R&R Crane Assumptions...................................................... 23 Table 14. Generator R&R Crane Assumptions............................................................................. 23

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1. Introduction
Global Energy Concepts, LLC (GEC) has developed an operations and maintenance (O&M) cost model for estimating O&M costs for commercial wind turbine generator (WTG) facilities. This model was developed under contract with the National Renewable Energy Laboratory (NREL). The overall objective of this model was to support the Low Wind Speed Turbine project goal of identifying ways to reduce the cost of energy for wind projects in low wind speed areas. The model considers the typical costs associated with ongoing operations, including scheduled maintenance, unscheduled repairs, site management, and support personnel, of a facility that comprises any number of conventional wind turbines. Data from a variety of wind power projects that represent different turbine types, turbine ages, and geographic locations have been used to develop the assumptions. Since the operating record for turbines larger than 1 megawatt (MW) is limited to only 25% of the expected 20-year life, the model is necessarily speculative with respect to costs in the last 75% of project life. There are no series-production turbines in the 2 MW and larger range in North America, so estimates for such machines use extrapolated data. Nevertheless, the model is expected to be a useful tool for understanding the relative influences of the factors that drive O&M costs. The model was created in an Excel workbook and will run on any PC with Microsoft Office. A brief user guide to the application is included in Appendix A. As delivered, the model includes a range of generic turbine sizes, with representative costs for parts and projected parts replacement rates, and default assumptions about staffing levels, labor rates, crane costs, etc. The user is only required to select the turbine rated power, pitch system type, rotor speed control type, and number of turbines for an as-is estimate of costs for a hypothetical project. However, the model is flexible. The user can change basic assumptions about the number of employees, labor rates, component costs, and crane rental rates. The model is predictive rather than prescriptive. It projects costs, but does not directly identify methods for reducing the cost of energy. A key feature of the model is that it allows relative impact of the various O&M cost contributors to be evaluated on a common basis; this facility has not been available up to now. An example is the cost associated with maintaining an electric blade pitch system versus the cost for a more conventional hydraulic pitch system. Also, in the course of developing the assumptions for the model, GEC had the opportunity to observe different strategies for efficiently operating wind power facilities and to solicit recommendations and comments from experienced operators. These recommendations are included in Section 7 of this report. The model produces estimates of O&M costs based on averages of past performance of equipment that is not always representative of current or future wind turbines. Significant changes have occurred in wind turbine technology over the past decade, in both scale and configuration. The megawatt-scale, pitch-regulated, variable-speed turbines that are common today have a relatively short track record. Most are still under warranty, so the reliability data for even this short time period are generally not available to the public. The component failures that do occur with newer machines often reflect a design that is not fully refined, and therefore may
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not be an accurate predictor of future reliability. The model does not reflect premature or serial failures, but rather uses failure rates that are appropriate for mature industrial equipment that has been field tested and proven. Another variable that has an uncertain effect on wind turbine reliability is the condition of the site. The wind regime, as characterized by mean wind speed or turbulence intensity, certainly affects the turbine load spectrum, but the effect of increased loading on the reliability of components has not been considered in this study. Other site conditions, such as extreme temperatures and blown dust, will affect turbine operation and may prematurely degrade components such as fluid lines, wiring insulation, and electronics. The model does not reflect these effects. Finally, not all turbine equipment is identical. The model assumes that all the turbines are equal in quality; that is, they are mature, proven designs, manufactured and installed with appropriate quality assurance measures, and supported by a competent service group. Still, variability between manufacturers, models, and even between individual turbines, is inevitable. These factors (limited performance data of short duration, different site conditions, and variability of equipment quality) present challenges to developing a universally applicable estimating tool. To the extent possible, the model is based on quantifiable data, but some values are based on engineering judgment, as noted in the text. As discussed in Section 6, the model projections have been benchmarked with actual performance for selected projects. However, neither GEC nor NREL can guarantee that the results of the model will accurately reflect any individual project at any given time.

2. Scope
The O&M cost model that is presented here is applicable to conventional, three-bladed WTGs installed on tubular towers. This configuration is the de facto standard for current machines and represents the bulk of machines installed in North America in the last decade. In general these machines include full-span-pitch blades, a planetary/helical gearbox, and an induction generator. Although direct-drive machines represent a 15% world market share, there are few in North America at this time. GEC has no access to the performance data for those machines. However, the model can be configured to accommodate a direct drive if the cost and performance data are available to the user. The generic turbines defined in the model include versions with either electric or hydraulic pitch systems and with either constant or variable rotor speed. No attempt has been made to estimate the costs associated with two- versus three-rotor blades, or with some of the recent innovative features such as permanent magnet generators. However, as stated previously, the model is flexible and has the capability to include any turbine configuration. The scope of this study and of the model is also restricted as follows:

Catastrophic events such as hurricanes, tornados, and lightning have not been considered. This is not to say that these events are not significant; lightning in particular has caused blade damage at numerous sites and will continue to be a risk as projects are installed in lightning-prone areas such as the Plains states. Retrofit work to remedy obvious design or manufacturing defects has not been included in the data that support the model. Components often fail during the first few years of a project, but we should not assume that these failures are representative of the reliability of that type of component. To do so would bias the failure distribution toward the anomalies rather than toward the norm. In some cases, the decision to exclude certain data is straightforward (e.g., where a serial failure has been declared). In other cases, the data point is an obvious outlier in the data set. These are discussed case by case as relevant. Repowering work (decommissioning equipment before the end of its useful life to install modern, usually higher powered equipment) has not been considered as part of the failure data. GEC has avoided data for projects where the motivation to maintain the equipment in optimal working condition has been damped by the prospect of decommissioning in the near future. Shipping and warehousing costs for parts are not included as line items. Given the variability and uncertainty of parts costs, and the number of options for warehousing spares, we may reasonably assume that shipping costs are included in the parts costs. Insurance costs were not included in the study; however, the model can be modified to include a placeholder. Balance-of-plant and substation maintenance costs were not specifically studied, but can be included with site maintenance costs at the users discretion.
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Offshore turbines are specifically excluded from this study. The O&M costs for an offshore installation are uniquely driven by accessibility for service and repair and are not consistent with land-based costs. However, the model can easily be modified to include aspects that are peculiar to offshore projects, such as access intervals and repair times. Land-lease costs, interconnect fees, and royalties are not considered to be O&M costs.

3. Background
O&M costs have long been an uncertain but significant component of the cost of energy from wind power facilities. Much of the current understanding of O&M costs is based on limited knowledge of short-term operating expenses from wind farms, many of which use older turbines that are not representative of current designs, and where the wind farm is much smaller than those being installed in the United States today. This information is combined with estimates about the long-term reliability and replacement costs of major turbine components. Because of the inexact nature of the input data, the O&M cost estimates that result from these analyses are imprecise; however, generally accepted approximations range from about $0.005 to $0.01/kilowatt-hour (kWh) for wind energy facilities in the United States. At low wind sites, where O&M per-turbine costs may remain fixed despite lower energy output, these costs may tend toward the high end of this range. Even higher costs may be incurred for smaller projects or where significant turbine repairs are necessary. Considering the goal of the Low Wind Speed Turbine project to reduce the cost of energy to $0.03/kWh at Class 4 wind sites, minimization of O&M costs should be a significant concern. The model, and the data contained within this report, will provide some insight into the various factors that affect turbine O&M costs.

4. Source Data
Data for this project have come from a variety of sources, including manufacturer publications, published case studies, expenditures and service logs from operating wind farms, and conversations and interviews with project managers and technicians. The quality and quantity of the available data can best be described as spotty. In some cases general estimates of overall maintenance costs for specific projects for periods of one or two years were available; in other cases detailed information on actual expenditures for a variety of turbines (but only for a snapshot of their operating life) was provided. As expected, the data are not in a consistent format, and are broken down into a surprising variety of categories for parts, labor, and downtime. Most importantly, there are no complete and consistent data for any project over the entire useful life of the turbines. Without exception, the older turbines (those reaching the end of their useful life) are smaller and simpler versions of the machines installed in the last five years. This distribution is consistent with the trend toward growth both in size and sophistication of wind turbines over the past 20 years. Following is a summary of the available data sources for this study:

Service logs from operating wind energy projects, which cover turbines that are smaller than 150 kW to nominally 2 MW, covering periods from one to six years. Parts consumption lists for operating projects, some of which include prices. Overall O&M summaries for current projects, including actual expenditures and projections. Spare parts price lists from manufacturers and receipts from actual projects. Interviews with operators and technicians about maintenance strategies, time to repair components, and time required for servicing. Manufacturer estimates of useful life and replacement rates for components. GECs general experience and collective knowledge from evaluating and monitoring a variety of wind projects over the past 19 years. Published studies that are specific to wind project O&M costs and reliability of industrial equipment in general.

Since many of the data used in the study are from private sources and are considered proprietary, GEC has made a conscious effort to avoid reference to specific project sites or equipment manufacturers. Most of the data presented here have been averaged, and where possible normalized, to avoid distinguishing any particular entry. References in the public domain, however, are acknowledged where appropriate.

5. Approach
This cost model is loosely based on previous efforts by GEC to estimate O&M costs for specific projects that comprise specific turbines. The general approach, carried through to this project, is to identify the cost contributors and assemble them into a structure that extrapolates those costs over the operating life of the project. The model assumes a project life of 20 years. Certainly some projects have passed the 20-year mark, and some have been curtailed early by repowering with new equipment. However, 20 years is a common assumption for financing purposes and is representative of the design life for most commercial turbines. Figure 1 shows the overall structure of the model. The database includes representative values for turbine and site service and repair parts, normalized to turbine size, height, and number. The required user inputs are in two broad categories: (1) characteristics related to the wind farm, such as number of turbines, assumed site capacity factor and expected sell price per kilowatt-hour; and (2) turbine characteristics, such as rated capacity, hub height, type of power conversion (fixed or variable speed) and pitch system.

Database Define Wind Farm


Number of turbines Capacity factor Power sell price

Define Turbine Scaling Rules Virtual Windfarm


Staffing Site equipment Site maintenance

Scaling Rules Virtual Turbine


Component list Repair/replace cost Failure rates

Rating Tower height Power conversion Pitch system

Life-cycle Estimator

Figure 1. Database architecture

By default, the model creates a generic wind turbine as a proxy for commercial turbines. The reasons for this are partly practical: historical data for many of the turbines are limited and the cost data are generally proprietary. More importantly, a generic turbine allows extrapolation, on a common basis, from small to large sizes. This in turn allows the user to evaluate the relative benefits and disadvantages of using fewer large machines versus more small machines for a particular project.

The default turbine proposed in the model is based on the conventional three-bladed, pitchregulated, upwind, tubular tower machine. The model offers selection sizes of 750 kW to 2.5 MW, with hub heights of 60 to 85 meters (m); this range brackets the current offerings in North America. Height is important in that it drives the cost of the crane used for repairs. Table 1 presents some common tower heights for the range of turbine ratings covered in the model. Other combinations of turbine rating and tower height are viable, and depend largely on the wind class at a specific site. In some cases higher towers may be proposed for the turbines rated 2.0 MW and higher. Unfortunately the number of cranes in North America that are capable of lifting the nacelle components to heights above 85 m is limited, and the cost for this type of lift is difficult to estimate.
Table 1. Typical Turbine Rating/Tower Combinations
Size 750 kW 1.0 MW 1.5 MW 2.0 MW 2.5 MW Tower (m) 60 65 80 80 85 Configurations Hydraulic/electric pitch Hydraulic/electric pitch Hydraulic/electric pitch Hydraulic/electric pitch Hydraulic/electric pitch Variable/constant speed Variable/constant speed Variable speed only Variable speed only Variable speed only

In addition to turbine sizes, options are included for turbine type, pitch actuation system, and rotor speed control. Since hydraulically and electrically actuated systems are currently used on commercial equipment, the model includes both versions for any size range. Even though variable-speed operation is currently limited to only one manufacturer, this option is available for all sizes under the assumption that variable speed will be offered by more manufacturers as the patents expire or licensing agreements are put in place. Based on the input assumptions, the model uses scaling laws to populate the various cost contributors for the wind farm, based on the normalized data in the database. These costs are assigned to several categories (see Table 2). All these default assumptions are displayed, and the user can change any of them at will. This feature allows the user to refine the analysis to more accurately reflect conditions at a certain site, or even to add cost components that may be unique to a particular turbine. It also allows the user to evaluate the effect of different project configurations or operating strategies on O&M costs. For example, a 30-MW project that consists of 50, 600-kW turbines can be compared with one that consists of 10, 3-MW turbines.

Table 2. Cost Contributor Categories


Category Parts replacement Consumables Salaried labor Wage-based labor Site maintenance Equipment Description Costs for new and repaired parts, crane rental where required Turbine lubricants, filters and electricity consumed Site manager and office staff Maintenance and service technicians Roads, fences, building, meteorological equipment Trucks, tools, office and shop supplies

Maintenance costs associated with options such as extreme weather operation, condition monitoring equipment, and service elevators are not included in the generic configurations. These can be added to the model as line items at the users discretion. 5.1 Model Assumptions The O&M costs have been segregated into the broad categories of facility and turbine costs to develop the assumptions used in the model. This breakdown is summarized as follows: Facility Costs Operations and administration Site maintenance Equipment and supplies Turbine Costs Labor Parts Consumables

In general, the facility costs will remain constant over the life of the project; the turbine costs will escalate as the equipment ages and components reach the end of their useful life. The final result is approximated in Figure 2.

Facility Costs Turbine Costs Total Costs

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15

20

Figure 2. O&M Costs on a per-turbine basis

All costs for the entire period are presented in constant 2004 U.S. dollars (inflation in costs and labor rates is not considered). The next sections define the items in each category and discuss how the cost assumptions were reached.

5.2 Facility Costs Facility costs are linked to the size of the facility and are assumed to remain constant over the life of the project. This implies that the infrastructure is maintained in good condition for the projects life and that no improvements or expansions are made. The model assumes that the project has a minimum of 18 turbines and a maximum of 100 turbines; this is on the high end of most installed projects. The following sections describe the assumptions that are used to create example wind power projects and the method used to derive these assumptions. 5.2.1 Operations and Administration This category includes tasks associated with scheduling turbine crews, ordering and receiving parts for inventory, monitoring turbines status and performance, scheduling outside services for site maintenance, coordinating with the interconnect provider for outages and curtailments, and generating status and production reports. Since the most time-consuming activities are linked to the number of turbines, the model assumes that the manpower required for this activity depends only on the number of installed turbines, as opposed to the size of the turbine or the total capacity. For a small facility with fewer than 20 WTGs, these tasks are commonly assumed by a working manager who also covers some of the turbine maintenance activities. As the number of turbines increases to more than 20, a dedicated manager is commonly assigned. For facilities with more than 40 turbines, the model assumes an administrative assistant will be required, and an additional support person is assumed for more than 60 turbines. These assumptions are summarized in Table 3.
Table 3. Manpower Levels by Number of Turbines
Project Size Manager Support staff <20 WTGs 0.5 2140 WTGs 1 4060 WTGs 1 1 60100 WTGs 1 2

5.2.2 Site Maintenance Tasks that are not directly related to the turbine fall into this category. These include road maintenance, fence repair and brush clearing, maintenance building upkeep, meteorological equipment maintenance, and supervisory control and data acquisition (SCADA) system maintenance. Some activities may not be applicable to a specific site; others, such as snow removal, are applicable only to certain locations. The model assumes that these tasks are contracted to outside services, although depending on workload they may be assigned to turbine maintenance staff. Table 4 presents representative yearly expenditures.

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Table 4. Representative Yearly Site Maintenance Expenditures


Project Size Road grading Fences/clearing Building Meteorological SCADA <20 WTGs $3,000 $2,000 $5,000 $5,000 $1,000 2140 WTGs $6,000 $4,000 $10,000 $10,000 $2,000 4060 WTGs $9,000 $6,000 $15,000 $15,000 $3,000 6080 WTGs $12,000 $8,000 $20,000 $20,000 $4,000 80100 WTGs $15,000 $10,000 $25,000 $25,000 $5,000

5.2.3 Equipment and Supplies Vehicles, tools, personal protection equipment, and supplies are collected in this category. General practice, for safety as well as practical reasons, is to dispatch two-person crews for any turbine maintenance work other than resetting faults. One vehicle and tool set are required per crew. Basic maintenance tools, special tools such as fixtures and rigging for removing large components, or remote terminals for communicating with the turbine controller for troubleshooting purposes, are provided with the initial turbine supply; replacements are included annually. Miscellaneous supplies are estimated for offices (paper, copier, utilities) and shops (fuel, personal protective equipment, rags, cleaners). Table 5 presents representative yearly expenditures.
Table 5. Representative Yearly Expenditures for Equipment and Supplies
Project Size Vehicles Tools Shop supplies Office supplies <20 WTGs $12,000/crew $8000/crew $2500/crew $7000 2140 WTGs $12,000/crew $8000/crew $2500/crew $9000 4060 WTGs $12,000/crew $8000/crew $2500/crew $11000 6080 WTGs $12,000/crew $8000/crew $2500/crew $13000 80100 WTGs $12,000/crew $8000/crew $2500/crew $15000

5.3 Turbine Costs Turbine costs are linked to size and configuration, and generally escalate over time as the machines age and parts wear out. As discussed in the following sections, labor costs and replacement parts costs are linked to turbine size and age; consumables are linked only to turbine size. 5.3.1 Labor This category includes all staff who are dedicated to routine turbine maintenance, which includes regular turbine servicing, resets, troubleshooting, and minor repairs. Labor for major repairs, including any tasks that require a crane or more than a one hour of work for two technicians, is additionally included in the parts replacement cost. A survey of a variety of sites indicates that the number of turbines that one technician can cover depends only slightly on the size of the machine. Figure 3 shows the number of turbines per

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technician for 10 representative sites, for turbines in the range of 500 to 2000 kW. The average number of turbines per technician is 16 and 12 for the smaller and larger machines, respectively, but the scatter within any group is very high. For these projects, which range from 20 to more than 100 MW installed capacity, there is no consistent trend between project size and number of technicians.
# WTG / tech
25.0 # WTG / technician 20.0 15.0 10.0 5.0 0.0 0 500 1000 Turbine size (kW) 1500 2000

Figure 3. Number of turbines per technician

Several factors, including the tasks associated with regular servicing, the number of fault resets required, and the number and severity of repairs required, influence the time required to maintain a machine. Discussions with operators indicate that regular biannual service for modern turbines requires 2040 hours; the wide range is associated with pitch-regulated machines. Time for repair and fault resets, excluding retrofit activities, is approximately equivalent to service hours. This ratio of service to repair hours is reasonably consistent with older projects. As expected, the available data indicate that the total service hours per turbine, for similar size machines in the range of 500 to 1000 kW rated power, increases with turbine age and then levels off. Figure 4 shows the total annual service hours per turbine for four projects with similar size machines. The newer machines are slightly larger than the older machines, which suggests that their labor costs may level out at a higher cost as they age.

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250 200 150 100 50 0 0 2 4 6 8 Turbine Age 10 12 14 16

Figure 4. Annual service hours per turbine

Figure 4, shows the estimated hours required for turbine maintenance. Table 6 lists these assumptions for turbines. The labor hours assumed for maintaining higher rated turbines reflects the additional time required for turbine access and increased maintenance points. A reasonable number of hours that a full-time employee can effectively devote to maintenance work is 1800 per year; this accounts for 80 hours of vacation and sick leave, and 10% time devoted to administrative activities such as site meetings and safety training. The default crew sizes in the model are calculated by dividing the number of available hours per technician by the required hours per turbine. These estimates agree reasonably well with the data points for the first 10 years presented in Figure 3.
Table 6. Labor Hours per Turbine per Technician by Year
Period (Years) 750 kW to <1 MW >1 MW to 2.5 MW 15 100 200 610 150 250 1115 200 300 1620 250 350

These relationships are used as the default values in the model to estimate turbine maintenance hours given the turbine size and the number of turbines assigned to the project. Even though technicians are routinely dispatched in two-person crews for practical and safety reasons, in some cases odd numbers are used in the analyses. This extra person can be considered to account for turnover, training, and relief time for other employees. The model assumes the hourly rates for site staff that are shown in Table 7. These are representative of rates at operating projects. Technician rates will usually vary by skill level and experience, and often a crew will consist of a senior-level technician paired with a junior-level technician; these are average values for such a crew. Local rates can vary by 25% depending on the labor market in the area.

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Table 7. Annual Labor Rates


Base Site manager Technician Administrative assistant $30 $18 $33,000 Burdened @ 35% $40.50 $24.30

5.3.2 Parts This category includes all replacement parts for the turbines, exclusive of consumables. The parts that are considered candidates for replacement, including mechanical, electrical, and hydraulic components, are those that wear or deteriorate during normal use. Mechanical parts that experience any form of friction, contact, or flexure (e.g., bearings, seals, gears, diaphragms, brake and yaw pads) are all candidates, although (as discussed in Section 5.3.4), the failure rate can vary dramatically depending on the design life and duty cycle. Fatigue of mechanical and structural components is explicitly omitted from the model, which assumes that the load-carrying components are designed with adequate design life for the imposed loads and duty cycle. For example, gearboxes are included in mechanical wear items, but the main shaft and bedplate are excluded. By the same reasoning, blades are assumed to structurally survive for the design life of the turbine, although the model assumes that minor blade repairs or refinishing to compensate for damage or wear will be required. Hydraulic parts include pumps, valves and hoses, cylinders, and calipers. There are two distinct failure modes for these components, which have different failure distributions. In general, hoses will deteriorate over time regardless of use, and thus will have a calendar replacement schedule. The other components will wear based on use, and thus will have a replacement distribution based on operating hours. Electrical components such as contactors and circuit breakers that include contacts and moving parts are candidates for wear; main power cables are assumed to last for the life of the machine. Solid-state components such as control boards, power converter regulator boards, and soft-start trigger boards are included as they exhibit thermal deterioration over time. Motors and generators are included as the bearings wear mechanically and the windings fatigue thermally and mechanically with use. The parts are segregated into the categories shown in Table 8. For each category, the major cost items are included and minor cost items are placed into a miscellaneous category.

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Table 8. Parts Categories by System


Rotor Drive train Gearbox and lubrication Generator and cooling Brakes and hydraulics Yaw system Control system Electrical and grid Miscellaneous Blades, pitch bearings, pitch actuators Main bearing, seals, couplings Gearbox, lube pump, cooling system Generator, power converter, cooling system Hydraulics, calipers, shoes Calipers, wear pads CPU, interface modules, sensors Contactors, circuit breakers, relays, capacitors Hardware, other small mechanical, hydraulic and electrical parts not identified specifically

As discussed earlier, an effort has been made to standardize the turbines to allow comparison on a common basis for different size machines. The components included in the generic configuration represent the current state of the art for modern turbines currently being supplied, although specifics will vary in the type of components included. These assumptions are described below for each component category.

Rotor: The rotor is three-bladed with independent pitch for each blade. The pitch bearings are rolling-element type, and are periodically lubricated with grease. The pitch mechanism is one of two types: (1) hydraulic pitch systems, which include a pitch cylinder, proportional valve, crank arm mechanism, accumulator, and displacement transducer for each blade. The pump and position controller are common to all three mechanisms; and (2) electric pitch systems, which include a motor with position encoder, gear reducer, electronic drive, and backup battery bank for each blade. The position controller is common for all three mechanisms. Control and Monitoring: 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 (e.g., PT100s for the generator) are included in that component category. Drive Train: The drive train consists of a main shaft supported by two main bearings, coupled to the gearbox with a hydraulic shrink coupling. A composite tube with flexure connections is used to couple the gearbox to the generator. Electrical Power 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. Gearbox: 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.

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Generator: The generator is single-speed, induction type. The variable-speed machine includes a wound rotor and slip-rings. Cooling is provided by an integral forced-air system. Brake: The brake is a caliper-type located on the gearbox high-speed shaft. A dedicated hydraulic system provides pressure for the calipers. The brake is used only for parking, as the primary rotor brake is the blade pitch system. 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 electric-motor driven with a multiple-reduction gearbox. The number and size of the yaw drives increase with turbine size. Miscellaneous: An overall category for miscellaneous parts that includes a value for parts not identified specifically elsewhere, such as hardware (brackets, pins, fasteners), small hydraulics (hoses, valves), and small electrics (contactors, lights, switches, connectors).

Parts costs for each of the five generic turbine sizes were estimated from machine cost data. In some cases these data have been drawn from manufacturers price lists; in other cases they have come from actual receipts. The former data set is subject to an indeterminate markup; the latter is more limited in scope. All major wear parts are covered; minor parts are not included in the miscellaneous category. Those with a useful life approaching 20 years may be missing, but the impact of these omissions will be included in the margin of error for the major high-cost components. Although small parts will likely be replaced in their entirety as they fail, larger components will likely be rebuilt. This is especially true of the high-priced components like the gearbox and generator, but applies as well to contactors, yaw drives, and power converters. Estimated replacement costs used in the model are based on rebuild cost where appropriate. The parts quantities and costs for the five generic turbines used in the model, along with the relations used to develop these costs, are included in Appendix B. 5.3.3 Consumables Parts and supplies that are required for scheduled service, as opposed to repairs, are considered consumable. This category includes lubricants, filters, and cooling fluids. Parts such as brake pads and generator bushes, which are replaced indeterminately, are included in the parts category. Annual turbine services generally include filter elements and greasing of the main bearing, yaw bearing and gear, pitch bearings, and generator bearings. Gear oil is mineral, as opposed to synthetic, and, according to common practice, should be replaced every three years. The model assumes an offline gear oil filter system and annual oil sampling. Hydraulic fluid will be replenished as required; this is generally a minor expenditure. Table 9 lists these per-turbine consumable estimates for each generic turbine size in the model. Grease quantity is assumed to be scaled proportionally to turbine rated power. Consistent with the current gearbox design guidelines, gear oil quantity scales with turbine rated power at approximately 0.15 liters (L)/kW. Gear oil filter costs are assumed to increase linearly with

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gearbox oil quantity. Hydraulic filters are assumed to be constant with turbine size. Electricity for turbine ancillary equipment (heaters, lights, winch) is estimated at 2 kW/MW at $.05/kWh.
Table 9. Per-Turbine Annual Consumable Cost Estimates, $
Turbine Size Gear oil filter, ea Hydraulic filter, ea Offline filter, ea Hydraulic oil, @$40/L Gear oil, @ 3.70/L Yaw gear grease @15/tube Bearing grease @ $10/tube Oil testing, ea Electricity 750 kW 100 100 100 20 140 60 45 120 657 1 MW 133 100 100 20 187 80 60 120 876 1.5 MW 200 100 100 20 279 120 90 120 1314 2.0 MW 267 100 100 20 371 160 120 120 1752 2.5 MW 333 100 100 20 464 200 150 120 2190

5.3.4 Failure Rates 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, main, yaw and pitch bearings, generators, and yaw drives 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. Additionally, a miscellaneous category includes minor mechanical, hydraulic, and electrical parts such as fasteners, fittings, and switches, which are assumed to fail randomly throughout the project life. 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. The failure rates in the model are based on historical data from operating sites as well as published failure rates for similar components in similar applications. As discussed previously, the available data are sparse and incomplete. Although in some cases GEC has data for periods covering 20 years, these data are for different models and machine sizes throughout this time span. There are no reliable data for any one type of machine for a complete life cycle. Also, the meaning of failure is not always clear, as parts are sometimes replaced when they start to fail, and at other times when they have completely stopped functioning. For some part types (e.g., a

17

control module), failure is definitive, but in other cases (e.g., a gearbox) a wide range of acceptable operating conditions may span significant periods of time. Table 10 summarizes the failure rates, in terms of mean time between failures (MTBF), assumed in the model default turbines, along with representative failure rates from three other sources. MTBF, also referred to as mean life, is the period of time in which half a given population of like components is expected to fail. MTBF is a common metric used in reliability studies. It is related to the Weibull characteristic life by the following relation:
MeanLife = CharcteristicLife (ln 2) 1

Table 10. Estimates of Failure Rate Mean Life


Component Blade failure Blade refurbishment Gearbox major failure Gearbox helical section rebuild Gearbox planet and helical rebuild Generator major failure Generator bearing replacement Yaw drive Yaw sliding pads Pitch bearing Main bearing Pitch cylinder Hydraulic valve Accumulator Hydraulic pump Brake caliper Lube pump Cooling fans Main contactor Main circuit breaker Control board, main Sensor, static Sensor, dynamic Power electronics Soft starter GEC model [C] [D] [C] 24 24 [C] 15 [C] 9 [C] [C] 9 11 5 11 8 11 14 17 25 12 12 10 12 25 Vachon [A] 17 14 15 10 10 10 10 10 20 Manufacturer Estimates >20 >20 15 10 >20 >20 >20 510 10 5 20 10 >20 1015 1015 Weibull Database [B] 14 -24 28 14 1424 42 14 14 14 26 16 14 10 28 33 7 23

A Vachon, W.A. Modeling the Reliability and Maintenance Costs of Wind Turbines Using Weibull Analysis. Windpower 96 Conference Proceedings. B Barringer Associates, Inc. Weibull Database. www.barringer1.com/wdbase.htm. C Assume 5% random failure rate for 20-year project life. D Assume 100% require refurbishment over 20-year project life.

The discrepancies in Table 10 for any one component can be partially explained by the uncertainty of the sources. The data presented by Vachon are limited to one particular era of wind turbines that had operated for 14 years at the time of the study, with missing data for a

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portion of the early years. Vachon also assumed a constant shape parameter of 3.5, which represents a symmetrical distribution. This is not consistent with the shape parameters in the Weibull database, which are generally less than 2. The data set for the Weibull database includes a wide variety of component types and operating conditions, and is not necessarily representative of the purpose-designed components in a commercial wind turbine. Appendix C discusses the failure rate assumptions used in the model for selected components, along with GECs rationale for selecting the Weibull parameters. 5.3.5 Time to Repair The values used in the model for time to repair or replace a component are based on discussions with operators and technicians and estimates provided by several manufacturers. In some cases GEC did attempt to verify these estimates with service logs, but the lack of consistency in the recording and presentation of the logs allowed for only a rough check. The model only includes time for repair of major components; that is, those that require rigging of some sort and a repair time of more than two hours. Repair time for all other components is assumed to be covered by the general service hours allocated in Section 5.3.1. The model assumes that where required, replacement parts are readily available and that no significant transport or wait time is required. This is consistent with most large facilities that have a stock of spares, including gearbox and generator, but this may not be a valid assumption for smaller facilities that use a central manufacturers depot for parts. Table 11 lists the assumed repair times in man-hours. These include shop preparation time.

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Table 11. Assumed Repair Time (Man-Hours)


Turbine size 1 Blade Pitch cylinder Pitch bearing Pump and hydraulics Pitch position transducer Pitch motor Pitch gear reducer Pitch drive (electronic) Main bearing High-speed coupling Gearbox remove and replace Lube pump Cooling fan/pump Generator R&R 2 Generator bearing replacement Power electronics Generator cooling fan Generator contactor Brake caliper Accumulator Hydraulic pump Hydraulic valve Yaw drive R&R Yaw caliper Yaw sliding pad Main circuit breaker Soft starter Pitch gearbox R&R
1 2

750 kW 30 6 50 8 4 4 6 4 100 12 70 4 4 16 10 8 4 4 6 4 4 4 8 8 8 4 8 6

1 MW 30 10 50 8 4 4 6 4 110 12 80 4 4 18 10 8 4 4 6 4 4 4 8 8 8 4 8 10

1.5 MW 40 12 60 8 4 4 6 4 120 12 90 4 4 20 10 8 4 4 6 4 4 4 8 8 8 4 8 12

2.0 MW 40 14 70 8 4 4 10 4 130 12 100 4 4 22 10 8 4 4 6 4 4 4 8 8 8 4 8 14

2.5 MW 50 16 80 8 4 4 12 4 150 12 120 4 4 24 10 8 4 4 6 4 4 4 8 8 8 4 8 16

Assumes removal of one blade only In situ replacement

5.3.6 Cranes 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. That is, the advantages of multiple replacements with one crane rental will not be realized (or required) for a site that follows the failure assumption proposed in the model. Crane rental costs are driven by crane capacity and mobilization time. Discussions with crane rental companies confirm the conclusions from previous studies: the crane capacity required for removal and replacement (R&R) of the two large components (gearbox and generator) is driven by height, not weight. Two common crane typesconventional crawler cranes and truckmounted cranesare appropriate for wind turbine component replacements. Cost for the former is driven by mobilization, as the crane and boom are shipped in pieces and require 10 to 20

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truckloads, depending on height. Hydraulic truck-mounted cranes use a telescopic boom and require only one to three additional loads for counterweights, and 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. For both cranes types, the height and reach are maximized by adding boom extensions (fixed jib or luffing jib) to obtain the required reach over the nacelle structure. As height and reach increase, additional counterweight must be attached to the crane body. The lift capacity decreases with height and reach. Fortunately, the weights of major turbine components are relatively small compared to crane tonnage, so that in most cases a given crane can be maximized for height. Figure 5 and Figure 6 show representative weights for gearboxes and generators for current model wind turbines.
20 18 16 14 Weight (mt) 12 10 8 6 4 2 0 0 500 1000 1500 Rated Power (kW) 2000 2500 3000 y = 0.0072x - 0.2467 2 R = 0.8134

Figure 5. Representative gearbox weight

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10.0 9.0 8.0 7.0 Weight (mt) 6.0 5.0 4.0 3.0 2.0 1.0 0.0 0 500 1000 1500 2000 2500 3000 Rated Power (kW) y = 0.0031x + 1.3789 R = 0.6208
2

Figure 6. Representative generator weight

In general, the candidate cranes for wind turbine work are limited to discrete sizes, and not all of these are readily available near the turbine site. Figure 7 shows example costs for cranes used for R&R of a gearbox at projects in a variety of locations, along with estimates for similar work provided by crane leasing companies. The lower tonnage equipment is truck-mounted hydraulic equipment and the higher tonnage is conventional crawler type.
100000 90000 80000 Cost per Crane Event ($) 70000 60000 50000 40000 30000 20000 10000 0 0 100 200 300 400 500 600 700

y = 147.55x - 21150 R = 0.8159


2

Tonnage (mt)

Figure 7. Crane costs by tonnage

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Table 12 through Table 14 list appropriate cranes for the five generic turbine sizes proposed in the model, along with representative costs for one day of R&R work and in/out mobilization. These are the default values in the model. The associated costs, which are based on experience with operating projects, include a second assembly crane, fuel, insurance, operator, and rigger for a lattice-type crawler crane. Mobilization cost assumes one day of travel each way from the rental depot. For the larger turbines, it is becoming more common to offer a nacelle-mounted crane for removal of the generator. This option is available on several large commercial machines, but there is little evidence the internal option is being purchased. Thus, the model currently assumes no internal crane to remove and replace the generator or other components for 2- and 2.5-MW models. Crane costs can be added or removed in the entry sheet, thus simulating an internal or external crane. An example of this is shown at the end of Section 6.
Table 12. Gearbox and Main Bearing R&R Crane Assumptions
Turbine size Tower height Gearbox weight Crane size Crane type R&R cost 750 kW 60 m 5.5 mt 200 ton Truck-mounted hydraulic $10,000 1.0 MW 65 m 7 mt 240 ton Truck-mounted hydraulic $25,000 1.5 MW 70 m 10 mt 400 ton Conventional crawler $50,000 2.0 MW 80 m 16 mt 400 ton Conventional crawler $70,000 2.5 MW 85 m 18 mt 650 ton Conventional crawler $90,000

Table 13. Blade and Pitch Bearing R&R Crane Assumptions


Turbine size Tower height Blade weight* Crane size Crane type R&R Cost 750 kW 60 m 1.5 mt 200 ton Truck-mounted hydraulic $10,000 1.0 MW 65 m 2.9 mt 240 ton Truck-mounted hydraulic $25,000 1.5 MW 70 m 4.3 mt 400 ton Conventional crawler $25,000 2.0 MW 80 m 6.5 mt 400 ton Conventional crawler $70,000 2.5 MW 85 m 8.1 mt 650 ton Conventional crawler $90,000

* Griffin, Dayton A. WindPACT Turbine Design Scaling Studies Technical Area 1 Composite Blades for 80- to 120-Meter Rotor, March 21, 2000 March 15, 2001. National Renewable Energy Laboratory. NREL/SR-500-29492, April 2001.

Table 14. Generator R&R Crane Assumptions


Turbine size Tower height Generator weight Crane size Crane type R&R cost 750 kW 60 m 3.5 mt 200 ton Truck-mounted hydraulic $10,000 1.0 MW 65 m 4.6 mt 200 ton Truck-mounted hydraulic $25,000 1.5 MW 70 m 6 mt 240 ton Truck-mounted hydraulic $25,000 2.0 MW 80 m 7.5 mt 400 ton Conventional crawler $0 2.5 MW 85 m 9 mt 650 ton Conventional crawler $0

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6. Results
The model provides results in a variety of forms, including cost tables for each major category on a project, per-turbine, and per-kilowatt-hour basis. Tables also list the cost assumptions for all turbine parts and the total number of parts used in the 20-year project life. Copies of complete results from each model run are included in Appendix D. The results show total costs associated with scheduled maintenance, unscheduled maintenance, and levelized replacement costs (LRC). The last category is commonly used to estimate reserves that will be required for major component overhauls or replacements. The failure rate and cost estimates provided by the model could be used to inform the process for establishing the required monetary reserves to cover LRC. Also, the model does not account for lost revenue caused by turbine downtime for repair or service, as this is usually accounted for in the project availability assumptions. Figure 8 presents graphical results of executing the model with the five generic turbine sizes. The chart shows estimated costs on a per turbine basis. The configuration for each size is consistent with most currently available commercial turbines. The project size in each case is 60 MW and the calculations assume a capacity factor of 35%.
Turbine Cost Comparison Study
Annual Average over 20 years, 60 MW Project Size (includes levelized replacement costs)
60,000

50,000

$ / Turbine (2004 constant)

40,000

30,000

20,000

10,000

0 Parts Replacement (Hardware, Addt'l Labor, Crane) Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total

Category 1000 kW, const. spd, hydraulic, 65-m tower 2000 kW, variable speed, electric pitch, 80-m tower

750 kW, const. spd, hydraulic, 60-m tower 1500 kW, var. speed, electric 80-m tower 2500 kW, variable speed, electric pitch, 80-m tower

Figure 8. Cost per turbine ($), 20-year project life

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The O&M cost estimates for the five turbine sizes demonstrate that the major contributor to overall O&M costs over the project life is parts replacement, followed by labor. Figure 9 shows that in the first 5 years, parts costs are estimated to be 30% of the total cost, and by the end of the project life, they exceed 65% of the total cost. Additionally, if the 20-year average of $37,000 per turbine were used to gauge warranty costs for contract negotiations, rather than the average for years 15 of $19,000, valuable reserve funds could easily be forfeited to the warranty service provider.
Average O&M Cost per Turbine 1500 kW, variable speed, electric pitch, 80-m hub height, 60 MW Project Size
Includes levelized replacement costs 60000 Average Cost ($/turbine) 50000 40000 30000 20000 10000 0 Equipment Site Maintenance Wage-based Labor Salaried Labor Consumables Parts Replacement (Hardware, Addt'l Labor, Crane) Average yr 1-5 600 353 3791 5231 2348 6333 Average yr 6-10 600 353 4633 5231 2348 18588 Avg yr 11-15 600 353 5897 5231 2348 29695 Avg yr 16-20 600 353 6739 5231 2348 36154

Period

Figure 9. O&M Costs per turbine, 5-year averages

Looking at the 1500 -W turbine size in the study, parts costs are dominated by the failure of large parts that require the use of a crane (see Figure 10 and Figure 11).

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Annual Turbine O&M Costs


Based on 2004 dollars Includes levelized replacement costs

60000

50000

40000 $ / turbine / yr

30000

20000

10000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

Figure 10. Annual turbine O&M costs


Parts Replacement Breakdown

59%

38%

3% Parts Crane Additional Labor

Figure 11. Crane costs

The bumpiness is an artifact of the high-cost infrequent events, and will be accentuated as the number of turbines in the project decreases. An indication of where the high costs are occurring can be found in Figure 12, which shows that the gearbox (including lubrication) and rotor systems are the largest cost drivers.

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Parts Costs, by System, 20 Year Total


1500 kW, 60 MW Project Size, Variable Speed, Electric Pitch
(Includes levelized replacement costs)
Brakes & Hydraulics Electrical and Grid Misc. (All others) Control System Gearbox and Lube Rotor
Brakes & Hydraulics 6%

Drivetrain Generator and Cooling Yaw System


Control System 5% Drivetrain 1% Electrical and Grid 2%

Yaw System 3%

Rotor 21%

Misc. (All others) 1%

Gearbox and Lube 38%

Generator and Cooling 23%

Figure 12. Parts costs over 20 years, by system

A closer examination shows the failure distribution for some major components in each system (see Figure 13). An increase in major failures is noticeable around year 7 when the first gearbox failures are assumed to occur, and later in year 10 when coincident gearbox and structural blade failures are projected.
Cumulative failures or replacements by year (major components)
Repair or Total Failures Replacements over 20 yrs / in 20 yrs per initial qty parts Project in fleet (%) 3 72 1 4% 100% 4%

System
Rotor Drivetrain

Component
Blade--struct. repair Blade--nonstruct. repair Main bearing

1 0 6 0

2 0 6 0

3 0 6 0

4 1 6 0

5 0 6 0

6 0 6 0

7 1 6 0

8 0 6 0

9 10 11 12 13 14 15 16 17 18 19 20 0 6 0 1 6 1 0 6 0 0 6 0 0 6 0 1 6 0 0 6 0 0 6 0 1 6 0 0 6 0 0 6 0 1 6 1

Parts in Project 72 72 24

Gearbox and Lube Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed only Generator and Cooling Generator--rot. & brgs Generator--brgs only Power electronics Total

0 0 0 0 0 0 6

0 0 0 0 0 1 7

0 0 0 0 0 1 7

0 0 0 0 0 1 8

0 0 0 0 1 2 9

0 0 0

0 1 1

0 0 0

0 1 1

1 1 1

0 2 2

0 2 2

0 1 1

0 3 3

0 2 2

0 3 3

0 2 2

0 3 3

0 3 3

1 2 2

24 24 24 24 48 24

1 15 15 1 43 26

4% 63% 63% 4% 90% 108%

0 0 0 0 1 0 0 0 0 0 0 0 0 0 1 1 2 2 3 4 4 6 5 6 7 6 7 7 6 5 1 2 2 3 3 3 2 4 3 3 3 3 3 3 3 8 13 10 14 19 17 18 17 22 20 21 21 22 21 22

Figure 13. Failure distribution over 20 years, major parts

Although the timing and frequency of these events will vary from site to site, their occurrence will have a major impact on site resources. Projects usually maintain budget reserves for just this contingency, and may rely on additional short-term labor resources. A trend in O&M costs as turbine size increases can be demonstrated with two additional common metrics that are used to evaluate project and turbine performance. Higher rated turbines

27

are projected to cost less per kilowatt irrespective of age. This effect is demonstrated in Figure 14, which shows three turbine sizes of identical architecture (variable speed, electric pitch, 80-m towers).

Average Project Cost, 60 MW Variable Speed, Electric Pitch, 80-m Hub Height 40.0 35.0 Cost per Turbine ($ / kW) 30.0 25.0 20.0 15.0 10.0 5.0 0.0 Average yr 1-5 Average yr 6-10 Avg yr 11-15 Year 1500 2000 2500 Avg yr 16-20 20 yr Avg

Figure 14. Average cost per kW, 60-MW project

Finally, Figure 15 shows the per kilowatt-hour change in cost. The trends for this metric parallel the trends shown above. This must be so, because a constant capacity factor of 35% has been used in all the models. Figure 16 is an annual look at the data in Figure 15. Along with Figure 17, it shows that the high O&M cost for 2500 kW turbines in years 1620 was caused by a compounding of failures in year 16.

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Average Project Cost 0.012

0.010

0.008 Cost ($ / kWh)

0.006

0.004

0.002

0.000 Average yr 1-5 Average yr 6-10 Avg yr 11-15 Year 1500 2000 2500 Avg yr 16-20 20 yr Avg

Figure 15. Average cost per kWh, 60-MW project

Annual Project Cost


3000

2500

2000 Cost ($ / kW)

1500

1000

500

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Year 1500 2000 2500

Figure 16. Annual project cost

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Cumulative failures or replacements by year (major components)


Repair or Total Failures Replacements over 20 yrs / in 20 yrs per initial qty parts Project in fleet (%) 3 72 1 4% 100% 4%

System
Rotor Drivetrain

Component
Blade--struct. repair Blade--nonstruct. repair Main bearing

1 0 3 0

2 0 4 0

3 0 3 0

4 0 4 0

5 0 4 0

6 1 3 0

7 0 4 0

8 0 3 0

9 10 11 12 13 14 15 16 17 18 19 20 0 4 0 0 4 0 0 3 0 1 4 0 0 3 0 0 4 0 0 4 0 0 3 0 1 4 1 0 3 0 0 4 0 0 4 0

Parts in Project 72 72 24

Gearbox and Lube Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed only Generator and Cooling Generator--rot. & brgs Generator--brgs only Power electronics Total

0 0 0 0 0 0 3

0 0 0 0 0 0 4

0 0 0 0 0 1 4

0 0 0 0 0 1 5

0 0 0 0 0 1 5

0 0 0 0 1 1 6

0 0 0 0 1 1 6

0 1 1 0 2 1 8

0 0 0

0 1 1

0 1 1

0 1 1

0 1 1

0 1 1

0 1 1

0 2 2

1 2 2

0 1 1

0 2 2

0 1 1

24 24 24 24 48 24

1 15 15 1 43 26

4% 63% 63% 4% 90% 108%

0 0 1 3 1 2 6 11

0 0 0 0 0 0 1 0 0 0 2 3 4 3 4 4 4 4 3 4 1 2 1 2 2 2 2 1 2 2 8 12 10 11 12 13 18 10 13 12

Figure 17. Annual failures of 2.5 MW major components, 60-MW project size

A change in architecture such as hub height can affect the O&M costs, so the model is useful for making project development decisions in conjunction with other estimates of project performance, such as hub-height power production. Figure 18 shows the effect of increasing the tower size from 80 to 100 m.
Average Project Cost (2.5 MW turbines, 60 MW Project Size, no internal crane) 35.0 30.0 25.0 Cost ($ / kW) 20.0 15.0 10.0 5.0 0.0 Average yr 1-5 Average yr 6-10 Avg yr 11-15 Tow er Height 80m 100m Avg yr 16-20 20 yr Avg

Figure 18. Estimated O&M costs for 2.5-MW Turbines on 80-m versus 100-m towers

Other studies, such as whether O&M cost savings can be achieved by using an internal crane, can be performed. In Figure 19, the comparison shows savings of more than $2 million if an internal crane can lift blades and generators. The developer may be able to decide whether to use the internal crane based on expected use and the additional cost of an internal crane.

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Annual Project Cost Internal v. Conventional Crane, Blade and Generator Repair (2.5 MW turbines, 60 MW Project Size )
30,000 25,000 20,000 ($000) 15,000 10,000 5,000 0 100m, no internal crane 100m, internal crane

Average yr 1-5 768 667

Average yr 6-10 1213 1089

Avg yr 11-15 1534 1433 Tow er Height

Avg yr 16-20 1822 1698

20 yr Total 26686 24430

100m, no internal crane

100m, internal crane

Figure 19. Effect of internal crane on O&M costs

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7. Reducing O&M Costs


Discussions with operators revealed several approaches to project operations that may reduce O&M costs. All these tactics are currently being implemented to some degree at most large wind projects, and, except for Innovative Rigging and Tooling, are common strategies for any industrial operation. 7.1 Assign Tasks to Outside Services Owners typically contract outside service organizations to provide some or all of the O&M services, especially in the early years of a project. After several years, the owner may then decide to self-manage the project. Irrespective of who manages the project, specialty tasks that require specific training or equipment, such as road maintenance or transformer inspections, are usually hired out. Depending on the workload caused by repair activities, a project may contract an outside service to perform biannual turbine servicing. This is not necessarily a less expensive option per turbine, but it does allow the project to focus trained technicians on the difficult tasks and avoid hiring additional permanent staff. 7.2 Condition Monitoring All modern wind turbines have some form of condition monitoring for critical components. Critical parameters such as bearing and lubricant over-temperature are usually integrated into the turbine control system. Regular testing of gear oil and thermographic testing of transformers are now required (or at least recommended) by manufacturers. Vibration and acoustic analysis for bearings is increasingly being applied to gearboxes and generators, although the effectiveness of these methods in detecting early signs of failure is not conclusive. If the cost of these systems can be reduced and the confidence in their detection ability improved, they may identify bearing problems at an early stage. This will allow staff to track the deterioration of gearboxes and generators so replacements can be scheduled during low-wind periods or coincidentally with other crane work. 7.3 Aftermarket Components Common to any original equipment manufacturer (OEM) product, many of the parts used on a wind turbine are unique to the manufacturer and model. Wind turbine equipment has changed too rapidly, and equipment has been produced in too low volumes, to foster an aftermarket of major components. However, rebuild services for gearboxes, generators, and electrical components are available for older machines, although the advantages of economies of scale have not been realized. Potentially a mature aftermarket will develop to supply parts for the most recent phase of 700 to 2000 kW machines that have been installed in North America. 7.4 Innovative Rigging and Tooling Much of the risk associated with failure of large wind turbine components is due to the uncertain cost of crane rental. Travel costs for a conventional crane that comprises 12 to 20 truckloads can be very high, especially for a remote site. Nacelle gantry cranes for generator removal are

32

already available on some options. Alternate rigging and winching to remove blades, generators, and gearboxes could reduce both the cost and the risk to the project. 7.5 Recordkeeping Extracting useful data from the available record was seriously limited by the inconsistency of the recording methods. The service logs and parts costs data were usually stored separately, which complicated the process of correlating costs with failure events. Projects would be well served by establishing a common recordkeeping system that allows failure events and associated costs to be easily extracted.

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8. Conclusions
GEC has developed a tool for estimating O&M costs for wind energy projects. This model includes all the major cost contributors and is based on historical operating data from a variety of operating wind energy projects. The model was created in an Excel spreadsheet with a simple user interface and includes a range of generic turbines as examples. The model estimates O&M costs over the 20-year life of the project, and allows the user to modify the project and turbine specifics. This tool should prove useful to project developers, owners, and operators in their evaluation of turbine and project options.

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Appendix A

Using the O&M Cost Estimator Spreadsheet


Revision A, June 22, 2006 1.0 Overview The workbook consists of six visible worksheets. Sheet 1Revisions. This sheet contains the latest revision information. Sheet 2Instructions. Sheet 3User Entry. Interface sheet for user input. You may enter values for any cells that are white. Gray cells cannot be edited, since they contain calculations or default values from field data. The default data are protected, so you can use macro buttons to return to default values. Sheet 4Results Tables. Tables and charts of results based on input values in the User Entry Sheet. Sheet 5Comparison Studies. Up to three sets of results from the Results Tables sheets may be captured with the macro buttons provided in the Results Tables sheet. A graphical summary chart at the top is provided for quick visual comparison of studies. Input values from the User Entry sheet are also captured, and may be reloaded into the User Entry Sheet by using macro buttons on each captured study. Sheet 6Failure and Cost Distribution. Constant failure rates or Weibull failure rates for each component are computed for the original parts. For Weibull failure distributions, failure rates are applied to replacement parts as well. Replacement or repair costs for each part are then calculated for each year of operation. The costs include crane costs, additional labor costs, and the part replacement costs shown on the User Entry Sheet. Protection and Macros Except for user input cells on the User Entry sheet, and some user cells on the Failure & Cost Distribution worksheet, all cells are protected within each worksheet. This prevents inadvertent modification of the supporting calculations and data. Macros are used within the workbook, and must be enabled for the spreadsheet to function. Getting StartedThe User Entry Sheet After reading the instructions and familiarizing yourself with the workbook, access the User Entry sheet. Adjust the screen size to see the entire width of the sheet. Beginning at the top of the sheet and working down, you can characterize the wind farm and populate cells with known O&M costs. Initial estimates from data have been provided as defaults, which should provide a reasonable degree of accuracy for initial modeling. Refresh the
A-1

2.0

3.0

default data if you change parameters in Tables 1 and 2 by clicking the Use Default macro buttons associated with each table in Tables 3 through 7. If you plan to use values other than default values, you should configure the wind farm and turbine tables first, refresh with defaults second, and then enter the custom values; otherwise, you will have default values from a prior configuration. A quick check with the default values to the right of each field will confirm whether you have updated your configuration with the Reset Default macro. Some user notes appear on the User Entry worksheet that are reminders. You may add notes. 3.1 Table 1. Wind Farm Operations Enter appropriate values for your study. Capacity factor is used for determining the turbine operating costs per kWh (typically a range of 0.25 to 0.40 is used, depending on average site conditions expected for the 20year period). Energy sales price is currently used in the gross annual revenue calculation found in the Results Tables worksheet. The gross revenue is used merely as a relative reference to the O&M costs. Net revenue will not only be a function of O&M costs, but other costs not determined in the spreadsheet, such as land lease, insurance, taxes, etc. 3.2 Table 2. Wind Turbine Characteristics Enter or select from the drop-down list appropriate values for your study. Turbine rated power choices available are 7502500 kW in increments of 50 kW. Default data from the Facility Costs worksheet is based on either 750, 1000, 1500, 2000, or 2500, whichever your value is closest to. Power conversion choices are constant speed or variable speed. Default parts associated with each type of system are assigned quantities appropriate to the system. Parts not associated with each system will appear on the default parts list, but will have quantities of 0. Pitch control choices available are hydraulic, electric, or fixed. All pitchable systems are assumed to be full span. Default parts associated with each type of system are assigned quantities appropriate to three-bladed turbines. Parts not associated with each system will appear on the default parts list, but will have quantities of 0. Hub height is based on default values typical in the industry for each rating of turbine. Ultimately, tower height affects crane costs. If you are performing a comparison of O&M costs associated with various tower heights but do not have available crane cost data, you may manually enter the default value associated with each crane type or height found in the Facility Costs worksheet. 3.3 Table 3. Staffing Levels and Costs Rates for manager, technician, and administrative assistant may be adjusted, as well as the burden, which accounts for additional costs above a negotiated salary or wage such as Social Security, medical, and retirement benefits. Administrator costs are annual salary values; technicians are hourly wages. To calculate hourly wages from an annual salary, divide the annual salary by 2080, which is a standard man-year.

A-2

3.4 Table 4. Annual Turbine Consumables Default values are annual costs on a per turbine basis, and are driven by calendar rather than operating time. They are assumed to remain constant for 20 years using constant 2004 costs as a reference for default data. Additional cells are provided for additional consumable items and costs. 3.5 Table 5. Crane Cost (+Mobilization) Costs are driven to a large extent by mobilization, so you should obtain accurate data for the site. All parts replacements that require a crane assume the event is singular, rather than serial, and require a deployment for each failure except blade nonstructural repairs in the default parts list: all three blades are assumed to be repaired simultaneously with one mobilization. Additional cells are provided for additional crane costs that are associated with a specific component. If you select "TRUE" for any parts that require a crane in the parts list, the component name and crane data need to be added to the crane costs table. To ensure correct lookup of the crane cost, you should use the "Update Table 5" macro button at the top of the column, and then enter the appropriate crane cost to Table 5 adjacent to any components without values to update the component title in the user cell. 3.6 Table 6. Site Equipment, Supplies, and Maintenance You can supply your own values; however, site equipment and maintenance costs are small relative to the overall O&M costs. Additional cells are provided for additional items. 3.7 Table 7. Turbine Parts List Default values are based on field data. However, specific user data will provide more accurate results. If you choose to input different values, enter them in the user cells. Entering user values will override the default. To reset everything in the list to the default values, select the default macro button at the top of the table. A word of caution: You should copy the user values to a comparison study as a backup. If the user values are accidentally overwritten, the backup values can be reloaded. You may select Constant or Weibull failure distributions. Many of the default data are based on Weibull Database failure distributions and correlated to available data. However, some failure rates of major components tend to be constant (and random), and are more accurately modeled with a constant failure rate. Operational experience will provide the best guidance. You can study the effects of reduced part mean life by adjusting the Weibull alpha or beta parameters and looking at the adjacent mean life calculation. The Miscellaneous parts category in the default parts list is used to account for all the remaining smaller components of the turbine. Ideally, each has a unique failure distribution. In reality, the overall effects of parts listed in this category are expected to be minor in relation to the other parts. As operators become more familiar with the characteristics of their parts, those with high failure rates may be added to the list as separate parts to investigate the cost effect on overall O&M.

A-3

4.0

Viewing and Saving Results Initial results are best viewed by using the Results Tables tab. Each table and chart represents a different way of looking at the data. To provide some comparison studies, you may save the results to the Comparison Studies worksheet by selecting the appropriate capture macro. Up to three studies can be compared at one time. You should capture the initial study with all three macro buttons, so as not to have a study captured from prior use of the spreadsheet. This is useful to evaluate the sensitivity of a serial part failure, or adjusted cost, such as a labor rate increase. You should use the Saved As to save the file with an appropriate filename to protect a specific analysis. Problem Notification and Enhancement Requests We appreciate of any feedback you can provide. Your participation is very important, and can greatly improve the quality of the cost model for the entire user community. Please e-mail any problems or requests for enhancement to the following address: droberts@globalenergyconcepts.com or gec@globalenergyconcepts.com attention: Task Code N12 Project Administrator subject: Enhancement request or Problem notification

5.0

A-4

Appendix B Part Quantities and Costs

B-1

Part Identification
System Rotor Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive Main bearing High-speed coupling Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed only Lube pumps Generator and Cooling Generator--rot. & brgs Generator--brgs only Power electronics Motor, generator coolant fan Contactor, generator Brakes & Hydraulics Brake caliper Brake Pads Accumulator Hydraulic pump Hydraulic valve Yaw System Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing Control board, Top Control board, Main Control Module 750 24,500 2,450 1,470 6,200 3,780 1,000 2,000 1,015 2,100 4,500 2,045 65,030 37,160 18,580 1,000 16,800 1,650 18,000 257 830 1,170 200 800 1,200 120 4,683 250 400 2,850 2,350 2,900 580 1000 33,750 3,375 1,590 9,700 3,780 1,000 2,667 1,353 2,800 7,100 2,727 92,470 52,840 26,420 1,100 28,840 2,200 18,000 257 1,430 1,230 200 1,400 1,200 120 6,244 250 400 4,102 3,150 3,950 790

New Cost from Data ($/unit)


Rating 1500 52,200 5,220 1,860 16,700 3,780 1,000 4,000 2,030 4,200 13,400 4,091 151,900 86,800 43,400 1,400 52,850 3,300 18,000 257 2,620 1,370 200 3,000 1,200 120 4,683 250 400 6,853 4,700 6,000 1,200 New Cost Equation 2000 70,650 7,065 2,130 23,700 3,780 1,000 5,333 2,707 5,600 21,000 5,455 216,020 123,440 61,720 1,600 76,860 4,400 18,000 257 3,820 1,500 200 5,100 1,200 120 6,244 250 400 9,863 6,300 8,100 1,620 2500 89,150 8,915 2,400 30,700 3,780 1,000 6,667 3,383 7,000 29,800 6,818 283,850 162,200 81,100 1,900 100,870 5,500 18,000 257 5,010 1,630 200 7,700 1,200 120 7,805 250 400 13,083 7,850 10,200 2,040 y = 73.892x - 6437.3 y = 73.892x - 6437.3 y = 1.8249x + 3482 y = 13.991x - 4263.3 y = 5400 y = 1000 y = 4000*x/1500 y = 2900*x/1500 y = 600*x/1500 y = .1472x1.5616 y = 4500*x/1650 y = 28.176x1.2237 y = 28.176x1.2237 y = 28.176x1.2237 y = 1.55x + 1764.78 y = 68.614x - 27416 y = 2.2x none, 1 data point y = 285 y = 2.3892x - 960.16 y = 2.6579x + 9680.8 y = 200 y = 0.0038x1.8563 y = 1200 y = 120 y = 17.883x/qty y = 250 y = 400 y = 0.6535x^1.2659 y =6.275x y = 8.3429x - 471.43 y=0.2*Control Board Main avg cost, y = 5.51x 700.79: count, y = 15.637Ln(x) - 96.967 y=1320 y = 10.715x - 4633.7 y = 0.0001x2.5483 y = 4.0277x + 1630.6 y = 63.205x

Rebuild Cost Factor


750 0.50 0.05 0.30 1.00 0.70 1.00 1.00 0.70 0.70 1.00 1.00 0.70 0.40 0.20 1.00 0.70 1.00 0.15 0.90 1.00 0.15 1.00 1.00 1.00 1.00 0.70 1.00 1.00 1.00 0.50 0.50 1.00 25,067 3,584 1,583 7,145 3,931 1,076 2,076 1,128 2,176 6,390 2,272 66,353 38,483 18,882 1,076 17,102 1,839 18,151 332 906 1,283 200 876 1,276 158 4,834 401 551 4,740 2,350 2,900 580 1000

$ / Event
Rating 1500 52,956 6,581 2,087 17,834 3,931 1,076 4,076 2,143 4,276 15,668 4,318 153,601 88,501 43,854 1,476 53,228 3,489 18,151 332 2,696 1,483 200 3,076 1,276 158 4,834 401 551 9,121 4,700 6,000 1,200 2000 71,406 8,426 2,395 24,834 3,931 1,076 5,409 2,896 5,676 23,457 5,681 217,910 125,330 62,400 1,676 77,276 4,589 18,151 332 3,896 1,613 200 5,176 1,276 158 6,395 401 551 12,320 6,300 8,100 1,620 2500 90,095 10,503 2,702 32,023 3,931 1,076 6,742 3,610 7,076 32,635 7,045 286,118 164,468 82,007 1,976 101,324 5,689 18,151 332 5,086 1,743 200 7,776 1,276 158 7,956 401 551 15,918 7,850 10,200 2,040 Repair Description Structural fiber repair, replace with spare during repair Cosmetic skin repair; drop rotor and repair 3 at a time Rebuild seals and servo Replace Replace components only Replace Replace Rebuild, bearing replacement, refinish gears Replace IGBTs, repair driver board Replace Replace Rebuild, bearing replacement, refinish gears Rebuild, bearing replacement Rebuild HS side, bearing replacement Replace Rebuild rotor windings, replace bearings Replace bearings Replace IGBTs, repair driver board Replace Replace Replace seals Replace Replace Replace Replace Rebuild, bearing replacement, refinish gears Replace seals Replace Replace Swapout with spare, repair board Swapout with spare, repair board Replace

34,317 4,509 1,779 10,645 3,931 1,076 2,742 1,467 2,876 9,179 2,954 93,982 54,352 26,722 1,176 29,180 2,389 18,151 332 1,506 1,343 200 1,476 1,276 158 6,395 401 551 6,181 3,150 3,950 790

Drivetrain

Gearbox and Lube

Control System

Electrical and Grid

Misc. (All others)

Sensor, static Sensor, dynamic Main Contactor Main Circuit Breaker Soft starter Miscellaneous Parts

490 1,200 2,380 1,484 3,255 47,400

440 1,200 4,270 3,087 3,962 63,210

440 1,200 7,980 8,687 5,369 94,810

470 1,200 11,760 18,074 6,783 126,410

520 1,200 15,540 31,920 8,190 158,010

1.00 1.00 0.70 0.70 0.70 1.00

490 1,200 2,456 1,560 3,406 47,400

440 1,200 4,346 3,163 4,113 63,210

440 1,200 8,056 8,763 5,520 94,810

470 1,200 11,836 18,150 6,934 126,410

520 1,200 15,616 31,996 8,341 158,010

Replace Replace Swapout with spare, rebuild Swapout with spare, rebuild Swapout with spare, rebuild Replace

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Appendix C Failure Rate Assumptions

This appendix discusses the failure rate assumptions used in the model for selected components, along with GECs rationale for selecting the Weibull parameters.
Gearbox

Determining the failure rates for a gearbox is complicated by the number of premature failures that have occurred with various newer wind turbines. The reasons for these failures are varied and are the subject of much controversy, but indications are that they are attributable to either manufacturing quality lapses or inappropriate design decisions. GEC does not believe that it is reasonable to project these very short lives into the future, and concludes that these problems will be, and in many cases have been, resolved. Figure A-1 shows gearbox failures for a variety of turbines of sizes at different sites. In all cases, the year of failure is an average of a two or more year period. The trend line is a Weibull distribution through the seven non-premature failures, with a characteristic life of 27 years and a shape factor of 3.5. For comparison purposes, Vachon estimated a life of 12 to 20 years, but this estimate was based on pre-1999 machines. Industry characteristic life estimates for gears in general range from 12 to more than 100 years, with a typical value of 28 years.
Gearbox Failure Rate
Failures/yr/turbine
0.1 0.08 0.06 0.04 0.02 0 0 5 10 15 20

Age (yr)
trend "Normal" Failures Premature Failures

Figure C-1. Gearbox failure rates

C-1

Generator

Determining the failure rates for a generator is analogous to the difficulty with gearboxes; recently installed machines have exhibited a number of early failures, in two distinct modes. The first is winding failure, which may be the result of inadequate insulation systems or inappropriate winding design. The other failure mode is early bearing fatigue, which may be attributable to inappropriate fits or poor lubrication. GEC believes these problems are localized and in many cases have been rectified with design or manufacturing improvements, and that a mean life of 25 years with a shape factor of 3.5 is reasonable, as indicated with the trend line (see Figure A-2). This value is slightly less than the typical industry-wide mean life of 38 years for a motor, but is reasonable considering that the duty cycle and operating environment for a wind turbine generator are more severe than for a typical process motor.
Generator Failure Rate
Failures/yr/turbine
0.120 0.100 0.080 0.060 0.040 0.020 0.000 0 5 10 15 20

Age (yr)
"Normal" Failures Premature Failures trend

Figure C-2. Generator failure rates Yaw Drive

The data available for yaw drive replacements are limited to the past 12 years. Before 1993, the turbines GEC evaluated used hydraulic yaw motors, whereas more modern machines use electric motor coupled to multistage reducers. The failure rate trend line presented in Figure A-3 uses a characteristic life of 12 years with a shape factor of 3.5. These values ignore the outlier point shown in the figure, which was assumed to be a serial replacement. The duty cycle on yaw drives may have increased since the introduction of sliding-pad type yaw bearings as opposed to the earlier low-friction ball bearings.

C-2

Yaw Drive Failure Rate


Failures/yr/turbine
0.6 0.5 0.4 0.3 0.2 0.1 0 0 5 10 15 20

Age (yr)
Yaw Gear (Reduction Unit) Premature Gear Failure Yaw Motor trend

Figure C-3. Yaw drive failure rates Pitch Cylinder

Minimal data were available for pitch cylinder failures, and it is not clear in which instances the cylinder was damaged irreparably. Figure A-4 shows a trend line for a characteristic life of 18 years with a shape factor of 2. However, GEC opted to use the vendor-proposed mean life of 10 years (Eta = 12, Beta =2). These values assume that seals will wear faster with the newer turbines than with the older styles because of the generally higher pitch activity demanded of modern pitch systems. The model assumes that the cylinder rod and body will last for the life of the turbine, but that the associated pitch servo valve will be replaced along with the seals.
Pitch Cylinder Failure Rate
0.1

Failures/yr/turbine

0.08 0.06 0.04 0.02 0 0 5 10 15 20

Age (yr)
Pitch Cylinder trend

Figure C-4. Pitch cylinder failure rates

C-3

Contactors

The duty cycle for the contactors in a wind turbine varies widely depending on the device it is driving and the site conditions. Machines that come on and off line frequently, or with highly variable wind direction, will have a higher duty cycle and can expect contactors to wear faster. Airborne dust and contaminants can cause electromechanical equipment to degrade early. Based on the data in Figure A-5, GEC assumed a characteristic life of 20 years for all contactors. This is a higher value than is commonly encountered in other industries, but may be the result of a generally lower duty cycle. The generic turbines presented with the model assume that the turbines are fitted with well-sealed and filtered enclosures. Small contactors (e.g., for capacitor switching or pumps) are assumed to be replaced; main and bypass contactors are rebuilt.
Contactor Failure Rate
0.10

Failures/yr/turbine

0.08 0.06 0.04 0.02 0.00 0 5 10 15 20

Age (yr)
>50 Amp <50 Amp trend

Figure C-5. Contactor failure rates Controllers

All modern turbines use modular industrial-grade solid-state controllers that are hardened for use in vibration environments. Failure of these components is usually due to either thermal degradation or transient voltage surges. Figure A-6 presents data for several types of controller boards, both interface modules and central processors. The assumed trend line has a characteristic life of 15 years and a shape factor of 2. The model assumes that major components such as control processors are repairable, but interface modules are not.

C-4

Control Board Failure Rate


0.080

Failures/yr/turbine

0.060 0.040 0.020 0.000 0 5 10 15 20 25

Age (yr)
Control Board trend

Figure C-6. Control board failure rates Sensors

The useful life for all turbine sensors varies widely. As might be expected, thermal sensors, which have no moving parts, appear to last much longer than anemometers. Figure A-7 shows failure rates for all sensors, along with an assumed trend line with a characteristic life of 12 years and a shape factor of 2.
Sensor Failure Rate
0.100 0.080 0.060 0.040 0.020 0.000 0 5 10 15 20 25

Failures/yr/turbine

Age (yr)
Sensor trend

Figure C-7. Sensor failure rates

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Appendix D Model Results

D-1

750 kW model Results


Table 1. Wind Farm Operations
Notes: Description: Capacity Factor (%) Number of Turbines Energy Sales Price ($/kw-hr.) Power Generated (MW) 35 80 0.055 60 750 kW, const. spd, hydraulic, 60m tower

Table 2. Turbine Characteristics


Rating Power Conversion Pitch Control Hub Height 750 Constant Speed Hydraulic 60

Table 3. Staffing Levels and Costs


Site Manager Salary Admin. Asst. Salary Sr. Tech Wage Jr. Tech Wage Totals

Salary ($/year) Wage ($/hr) 85,000 35,000 18.00 12.00

Burden (%) 35 35 35 35

Total $ $ $ $ 114,750 47,250 24.30 16.20

years 1-5 1 2 1 3

# of Staff 6-10 1 2 2 4

11-15 1 2 2 6

16-20 1 2 3 7

Staffing Costs ($/Year) years 1-5 6-10 114,750 114,750 94,500 94,500 50,544 101,088 101,088 134,784 360,882 445,122

11-15 114,750 94,500 101,088 202,176 512,514

16-20 114,750 94,500 151,632 235,872 596,754

Table 4. Annual Turbine Consumables


User Values Item Gear oil filter Hydraulic filter Offline-filter Hydraulic oil replenish Gear oil change (mineral) Yaw gear grease Bearing grease Oil Testing Electricity $/turbine 100 75 100 20 145 60 45 120 657 Default Values $/turbine 100 75 100 20 145 60 45 120 657

Table 5. Crane Cost (+Mobilization)


User Item Blade--struct. repair Blade--nonstruct. repai Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed o Generator--rot. & brgs Generator--brgs only Main Bearing Pitch Bearing Yaw Bearing $/event 10,000 10,000 13,000 13,000 13,000 8,000 8,000 13,000 10,000 13,000 Default $/event 10,000 10,000 13,000 13,000 13,000 8,000 8,000 13,000 10,000 13,000

Table 6. Site Equipment, Supplies & Maintenance


Annual Costs ($)
User $2,500 $5,000 $8,000 $2,500 $6,000 Total Equipment $5,000 $4,100 $2,500 $1,700 $800 Default 2,500 5,000 8,000 2,500 6,000 24,000 5,000 4,100 2,500 1,700 800 14,100

Total

1,322

1,322 Total Maintenance

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Table 7. Turbine Parts List Part Identification Constant Failure Rate


Failure Prediction (Constant Rate or Weibull Curve) Constant Rate Constant Rate Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Failures per 100 original parts by Year 20 5 100 5 12 12 15 12 15 3.5 2.0 1.1 3.5 2.0 10.8 10.0 10.7 10.8 12.5

Weibull Failure Rate


Mean Life (50% failures)

Repair/Replacement Costs
qty per turbine 3 3 3 3 1 3 0 0 0 Addt'l Labor to Repair / Replace (hr) 29 59 7 49 8 4 4 5 4

System Rotor

Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive

Alpha

Beta

Cost 24500 2450 1470 6200 3780 1000 2000 1015 2100

10

3.5

9.0

Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE

Parts in Project 240 240 240 240 80 240

Drivetrain

Main bearing High-speed coupling

Constant Rate Weibull Curve

5 25 3.5 22.5

1 1

4500 2045

101 12

TRUE FALSE

80 80

Gearbox and Lube

Gearbox--gear & brgs Constant Rate Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve

5 20 20 12 19 3.5 3.5 3.0 1.1 18.0 18.0 10.6 13.6

1 1 1 3 1

65030 37160 18580 1000 257

71 71 13 4 4

TRUE TRUE TRUE FALSE FALSE

80 80 80 240 80

Generator and Cooling

Generator--rot. & brgs Constant Rate Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve

5 17 15 19 20 3.5 2.0 1.1 2.0 15.3 12.5 13.6 16.7

1 2 0 1 3

16800 1650 18000 257 830

16 10 8 4 4

TRUE TRUE FALSE FALSE FALSE

80 160 80 240

Brakes & Hydraulics

Brake caliper Brake Pads Accumulator Hydraulic pump Hydraulic valve

Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve

10 10 6 12 12

2.0 3.0 3.0 3.0

8.3 5.3 10.6 10.6

2 2 4 1 3

1755 200 800 1200 120

6 0 4 4 2

FALSE FALSE FALSE FALSE FALSE

160 160 320 80 240

Yaw System

Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing

Constant Rate Weibull Curve Weibull Curve Weibull Curve

12 10 10

3.5 2.0 3.5

10.8 8.3 9.0

2 2 4 1

4683 250 400 2850

8 8 8 101

FALSE FALSE FALSE TRUE

160 160 320 80

Control System

Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic

Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve

15 15 15 14 12

2.0 2.0 2.0 2.0 2.0

12.5 12.5 12.5 11.7 10.0

1 1 4 7 4

2350 2900 580 140 1200

0 0 0 0 0

FALSE FALSE FALSE FALSE FALSE

80 80 320 560 320

Electrical and Grid

Main Contactor Main Circuit Breaker Soft starter

Weibull Curve Weibull Curve Weibull Curve

20 30 30

2.0 2.0 2.0

16.7 25.0 25.0

1 1 0

2380 1484 3255

4 4 8

FALSE FALSE FALSE

80 80

Misc. (All others)

Miscellaneous Parts

Constant Rate

47400

FALSE

80

D-3

750 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 750 Hydraulic Constant Speed 80 60 0.35 Project Parts Cost Breakdown Parts Crane 9,879,414 3,036,500 Gross Project Income / yr $10,117,800 Gross Turbine Income / yr $126,473 Annual Production (MW-hr) $183,960

Additional Labor 843194 Total 13,759,107

Total Project O&M Cost ($000) Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /Turbine Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kW Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kWh Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total 1 0.001 0.001 0.001 0.001 0.000 0.000 0.003 2 0.001 0.001 0.001 0.001 0.000 0.000 0.004 3 0.001 0.001 0.001 0.001 0.000 0.000 0.004 4 0.002 0.001 0.001 0.001 0.000 0.000 0.004 5 0.003 0.001 0.001 0.001 0.000 0.000 0.005 6 0.002 0.001 0.001 0.001 0.000 0.000 0.006 7 0.003 0.001 0.001 0.001 0.000 0.000 0.006 8 0.003 0.001 0.001 0.001 0.000 0.000 0.006 9 0.004 0.001 0.001 0.001 0.000 0.000 0.007 10 0.005 0.001 0.001 0.001 0.000 0.000 0.008 11 0.004 0.001 0.001 0.002 0.000 0.000 0.008 12 0.005 0.001 0.001 0.002 0.000 0.000 0.009 13 0.004 0.001 0.001 0.002 0.000 0.000 0.008 14 0.006 0.001 0.001 0.002 0.000 0.000 0.009 15 0.006 0.001 0.001 0.002 0.000 0.000 0.009 16 0.005 0.001 0.001 0.002 0.000 0.000 0.009 17 0.006 0.001 0.001 0.002 0.000 0.000 0.010 18 0.005 0.001 0.001 0.002 0.000 0.000 0.009 19 0.006 0.001 0.001 0.002 0.000 0.000 0.010 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 0.00 0.00 0.00 0.01 0.00 0.006 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.002 0.00 0.00 0.00 0.00 0.00 0.000 0.00 0.00 0.00 0.00 0.00 0.000 0.010 0.00 0.00 0.00 0.01 0.00 0.01 0.00 0.01 0.00 0.01 1 1.8 1.8 3.5 2.5 0.2 0.4 10.2 2 3.1 1.8 3.5 2.5 0.2 0.4 11.6 3 3.4 1.8 3.5 2.5 0.2 0.4 11.9 4 5.0 1.8 3.5 2.5 0.2 0.4 13.4 5 8.1 1.8 3.5 2.5 0.2 0.4 16.6 6 7.5 1.8 3.5 3.9 0.2 0.4 17.3 7 9.1 1.8 3.5 3.9 0.2 0.4 18.9 8 9.0 1.8 3.5 3.9 0.2 0.4 18.8 9 11.7 1.8 3.5 3.9 0.2 0.4 21.5 10 14.4 1.8 3.5 3.9 0.2 0.4 24.2 11 13.1 1.8 3.5 5.1 0.2 0.4 24.0 12 15.5 1.8 3.5 5.1 0.2 0.4 26.5 13 13.5 1.8 3.5 5.1 0.2 0.4 24.4 14 16.9 1.8 3.5 5.1 0.2 0.4 27.8 15 17.6 1.8 3.5 5.1 0.2 0.4 28.6 16 16.4 1.8 3.5 6.5 0.2 0.4 28.7 17 18.3 1.8 3.5 6.5 0.2 0.4 30.7 18 16.3 1.8 3.5 6.5 0.2 0.4 28.7 19 18.4 1.8 3.5 6.5 0.2 0.4 30.8 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 4.3 10.3 15.3 17.6 11.90 18.7 1.8 1.8 1.8 1.8 1.76 1.8 3.5 3.5 3.5 3.5 3.49 3.5 2.5 3.9 5.1 6.5 4.49 6.5 0.2 0.2 0.2 0.2 0.24 0.2 0.4 0.4 0.4 0.4 0.40 0.4 12.7 20.1 26.3 30.0 22.27 31.1 1 106 106 209 152 14 24 611 2 188 106 209 152 14 24 693 3 207 106 209 152 14 24 711 4 297 106 209 152 14 24 802 5 489 106 209 152 14 24 994 6 451 106 209 236 14 24 1040 7 544 106 209 236 14 24 1133 8 541 106 209 236 14 24 1130 9 700 106 209 236 14 24 1289 10 863 106 209 236 14 24 1452 11 786 106 209 303 14 24 1442 12 932 106 209 303 14 24 1588 13 809 106 209 303 14 24 1466 14 1013 106 209 303 14 24 1669 15 1058 106 209 303 14 24 1714 16 982 106 209 388 14 24 1723 17 1099 106 209 388 14 24 1839 18 979 106 209 388 14 24 1720 19 1107 106 209 388 14 24 1847 Average Average Avg yr 11- Avg yr 16- 20 yr yr 6-10 15 20 Total 20 yr 1-5 257 620 919 1058 14275 1125 106 106 106 106 2116 106 209 209 209 209 4185 209 152 236 303 388 5391 388 14 14 14 14 282 14 24 24 24 24 480 24 762 1209 1576 1799 26729 1865

1 1323 1322 2616 1895 176 300 7633

2 2355 1322 2616 1895 176 300 8665

3 2583 1322 2616 1895 176 300 8893

4 3718 1322 2616 1895 176 300 10028

5 6111 1322 2616 1895 176 300 12421

6 5635 1322 2616 2948 176 300 12998

7 6806 1322 2616 2948 176 300 14169

8 6757 1322 2616 2948 176 300 14120

9 8749 1322 2616 2948 176 300 16112

10 10790 1322 2616 2948 176 300 18153

11 9822 1322 2616 3791 176 300 18027

12 11644 1322 2616 3791 176 300 19849

13 10117 1322 2616 3791 176 300 18322

14 12658 1322 2616 3791 176 300 20863

15 13222 1322 2616 3791 176 300 21427

16 12276 1322 2616 4844 176 300 21534

17 13735 1322 2616 4844 176 300 22993

18 12240 1322 2616 4844 176 300 21498

19 13832 1322 2616 4844 176 300 23090

yr 6-10 15 20 20 yr Avg 20 yr 1-5 3218 7748 11493 13228 8922 14060 1322 1322 1322 1322 1322 1322 2616 2616 2616 2616 2616 2616 1895 2948 3791 4844 3370 4844 176 176 176 176 176 176 300 300 300 300 300 300 9528 15110 19698 22486 16706 23318

D-4

Annual Project Costs


Based on 2004 dollars Includes levelized replacement costs

Turbine O&M Costs


Based on 2004 dollars Includes levelized replacement costs

2000 1800 1600 $ / turbine / yr 1400 $ x 1000 / yr 1200 1000 800 600 400 200 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

25000

20000

15000

10000

5000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)

Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total

Consumables Wage-based Labor Equipment

Turbine Costs per kW Rated Power


Based on 2004 dollars Includes levelized replacement costs

Turbine Costs per kWh Produced


Based on 2004 dollars Includes levelized replacement costs

35 30 25 $ / kWh 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 $ / kW 20 15 10 5 0 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

0.012 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

D-5

1000 kW model Results


Table 1. Wind Farm Operations
Capacity Factor (%) Number of Turbines Energy Sales Price ($/kw-hr.) Power Generated (MW) 35 60 0.055 60 Notes: Description: 1000 kW, const. spd, hydraulic, 65m tower

Table 2. Turbine Characteristics


Rating Power Conversion Pitch Control Hub Height 1000 Constant Speed Hydraulic 65

Table 3. Staffing Levels and Costs


Site Manager Salary Admin. Asst. Salary Sr. Tech Wage Jr. Tech Wage Totals

Salary ($/year) Wage ($/hr) 85,000 35,000 18.00 12.00

Burden (%) 35 35 35 35

Total $ $ $ $ 114,750 47,250 24.30 16.20

years 1-5 1 2 1 2

# of Staff 6-10 1 2 1 4

11-15 1 2 2 4

16-20 1 2 2 6

Staffing Costs ($/Year) years 1-5 6-10 114,750 114,750 94,500 94,500 50,544 67,392 327,186 50,544 134,784 394,578

11-15 114,750 94,500 101,088 134,784 445,122

16-20 114,750 94,500 101,088 202,176 512,514

Table 4. Annual Turbine Consumables


Item Gear oil filter Hydraulic filter Offline-filter Hydraulic oil replenish Gear oil change (mineral) Yaw gear grease Bearing grease Oil Testing Electricity 133 100 100 20 192 80 60 120 876 133 100 100 20 192 80 60 120 876 User Values $/turbine Default Values $/turbine

Table 5. Crane Cost (+Mobilization)


Item Blade--struct. repair Blade--nonstruct. repai Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed o Generator--rot. & brgs Generator--brgs only Main Bearing Pitch Bearing Yaw Bearing User $/event 14,000 14,000 23,000 23,000 23,000 15,000 15,000 23,000 14,000 23,000 Default $/event 14,000 14,000 23,000 23,000 23,000 15,000 15,000 23,000 14,000 23,000

Table 6. Site Equipment, Supplies & Maintenance


Annual Costs ($)
User $2,500 $5,000 $8,000 $2,500 $6,000 Total Equipment $5,000 $4,100 $2,500 $1,700 $800 Default 2,500 5,000 8,000 2,500 6,000 24,000 5,000 4,100 2,500 1,700 800 14,100

Total

1,681

1,681 Total Maintenance

D-6

Table 7. Turbine Parts List Part Identification Constant Failure Rate


Failure Prediction (Constant Rate or Weibull Curve) Constant Rate Constant Rate Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Failures per 100 original parts by Year 20 5 100 5 12 12 15 12 15 3.5 2.0 1.1 3.5 2.0 10.8 10.0 10.7 10.8 12.5

Weibull Failure Rate


Mean Life (50% failures)

Repair/Replacement Costs
qty per turbine 3 3 3 3 1 3 0 0 0 Addt'l Labor to Repair / Replace (hr) 32 62 9 52 8 4 4 6 4

System Rotor

Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive

Alpha

Beta

Cost 33750 3375 1590 9700 3780 1000 2667 1353 2800

10

3.5

9.0

Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE

Parts in Project 180 180 180 180 60 180

Drivetrain

Main bearing High-speed coupling

Constant Rate Weibull Curve

5 25 3.5 22.5

1 1

7100 2727

107 12

TRUE FALSE

60 60

Gearbox and Lube

Gearbox--gear & brgs Constant Rate Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve

5 20 20 12 19 3.5 3.5 3.0 1.1 18.0 18.0 10.6 13.6

1 1 1 3 2

92470 52840 26420 1100 257

77 77 18 4 4

TRUE TRUE TRUE FALSE FALSE

60 60 60 180 120

Generator and Cooling

Generator--rot. & brgs Constant Rate Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve

5 17 15 19 20 3.5 2.0 1.1 2.0 15.3 12.5 13.6 16.7

1 2 0 2 3

28840 2200 18000 257 1430

18 10 8 4 4

TRUE TRUE FALSE FALSE FALSE

60 120 120 180

Brakes & Hydraulics

Brake caliper Brake Pads Accumulator Hydraulic pump Hydraulic valve

Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve

10 10 6 12 12

2.0 3.0 3.0 3.0

8.3 5.3 10.6 10.6

2 2 4 1 3

1845 200 1400 1200 120

6 0 4 4 2

FALSE FALSE FALSE FALSE FALSE

120 120 240 60 180

Yaw System

Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing

Constant Rate Weibull Curve Weibull Curve Weibull Curve

12 10 10

3.5 2.0 3.5

10.8 8.3 9.0

2 2 4 1

6244 250 400 4102

8 8 8 107

FALSE FALSE FALSE TRUE

120 120 240 60

Control System

Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic

Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve

15 15 15 14 12

2.0 2.0 2.0 2.0 2.0

12.5 12.5 12.5 11.7 10.0

1 1 4 11 4

3150 3950 790 190 1200

0 0 0 0 0

FALSE FALSE FALSE FALSE FALSE

60 60 240 660 240

Electrical and Grid

Main Contactor Main Circuit Breaker Soft starter

Weibull Curve Weibull Curve Weibull Curve

20 30 30

2.0 2.0 2.0

16.7 25.0 25.0

1 1 0

4270 3087 3962

4 4 8

FALSE FALSE FALSE

60 60

Misc. (All others)

Miscellaneous Parts

Constant Rate

63210

FALSE

60

D-7

1000 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 1000 Hydraulic Constant Speed 60 60 0.35 Project Parts Cost Breakdown Parts 9,716,424 Crane 4,006,200 Gross Project Income / yr $10,117,800 Gross Turbine Income / yr $168,630 Annual Production (MW-hr) $183,960

Additional Labor 668477 Total 14,391,101

Total Project O&M Cost ($000) Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /Turbine Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kW Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kWh Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total 1 0.001 0.001 0.001 0.001 0.000 0.000 0.003 2 0.001 0.001 0.001 0.001 0.000 0.000 0.003 3 0.001 0.001 0.001 0.001 0.000 0.000 0.004 4 0.001 0.001 0.001 0.001 0.000 0.000 0.004 5 0.002 0.001 0.001 0.001 0.000 0.000 0.004 6 0.003 0.001 0.001 0.001 0.000 0.000 0.006 7 0.004 0.001 0.001 0.001 0.000 0.000 0.006 8 0.003 0.001 0.001 0.001 0.000 0.000 0.006 9 0.004 0.001 0.001 0.001 0.000 0.000 0.007 10 0.004 0.001 0.001 0.001 0.000 0.000 0.006 11 0.004 0.001 0.001 0.001 0.000 0.000 0.007 12 0.005 0.001 0.001 0.001 0.000 0.000 0.009 13 0.005 0.001 0.001 0.001 0.000 0.000 0.008 14 0.007 0.001 0.001 0.001 0.000 0.000 0.010 15 0.006 0.001 0.001 0.001 0.000 0.000 0.009 16 0.005 0.001 0.001 0.002 0.000 0.000 0.009 17 0.006 0.001 0.001 0.002 0.000 0.000 0.009 18 0.006 0.001 0.001 0.002 0.000 0.000 0.010 19 0.006 0.001 0.001 0.002 0.000 0.000 0.009 1 1.7 1.7 3.5 2.0 0.2 0.4 9.5 2 2.5 1.7 3.5 2.0 0.2 0.4 10.3 3 4.1 1.7 3.5 2.0 0.2 0.4 11.9 4 4.6 1.7 3.5 2.0 0.2 0.4 12.4 5 6.0 1.7 3.5 2.0 0.2 0.4 13.8 6 8.3 1.7 3.5 3.1 0.2 0.4 17.2 7 10.7 1.7 3.5 3.1 0.2 0.4 19.6 8 9.7 1.7 3.5 3.1 0.2 0.4 18.6 9 12.9 1.7 3.5 3.1 0.2 0.4 21.8 10 10.9 1.7 3.5 3.1 0.2 0.4 19.8 11 13.0 1.7 3.5 3.9 0.2 0.4 22.7 12 16.5 1.7 3.5 3.9 0.2 0.4 26.2 13 15.8 1.7 3.5 3.9 0.2 0.4 25.6 14 19.9 1.7 3.5 3.9 0.2 0.4 29.7 15 18.0 1.7 3.5 3.9 0.2 0.4 27.7 16 16.8 1.7 3.5 5.1 0.2 0.4 27.6 17 18.1 1.7 3.5 5.1 0.2 0.4 28.9 18 19.0 1.7 3.5 5.1 0.2 0.4 29.8 19 17.9 1.7 3.5 5.1 0.2 0.4 28.8 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 3.8 10.5 16.6 18.8 12.43 22.1 1.7 1.7 1.7 1.7 1.68 1.7 3.5 3.5 3.5 3.5 3.49 3.5 2.0 3.1 3.9 5.1 3.51 5.1 0.2 0.2 0.2 0.2 0.24 0.2 0.4 0.4 0.4 0.4 0.40 0.4 11.6 19.4 26.4 29.6 21.74 33.0 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 0.00 0.00 0.01 0.01 0.00 0.007 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.002 0.00 0.00 0.00 0.00 0.00 0.000 0.000 0.011 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 1 1732 1681 3488 1966 235 400 9501 2 2493 1681 3488 1966 235 400 10263 3 4133 1681 3488 1966 235 400 11902 4 4589 1681 3488 1966 235 400 12358 5 6001 1681 3488 1966 235 400 13770 6 8313 1681 3488 3089 235 400 17205 7 10746 1681 3488 3089 235 400 19638 8 9664 1681 3488 3089 235 400 18556 9 12887 1681 3488 3089 235 400 21779 10 10917 1681 3488 3089 235 400 19809 11 12963 1681 3488 3931 235 400 22698 12 16457 1681 3488 3931 235 400 26192 13 15845 1681 3488 3931 235 400 25580 14 19934 1681 3488 3931 235 400 29668 15 18005 1681 3488 3931 235 400 27740 16 16787 1681 3488 5054 235 400 27645 17 18078 1681 3488 5054 235 400 28936 18 18982 1681 3488 5054 235 400 29840 19 17906 1681 3488 5054 235 400 28764 1 104 101 209 118 14 24 570 2 150 101 209 118 14 24 616 3 248 101 209 118 14 24 714 4 275 101 209 118 14 24 742 5 360 101 209 118 14 24 826 6 499 101 209 185 14 24 1032 7 645 101 209 185 14 24 1178 8 580 101 209 185 14 24 1113 9 773 101 209 185 14 24 1307 10 655 101 209 185 14 24 1189 11 778 101 209 236 14 24 1362 12 987 101 209 236 14 24 1571 13 951 101 209 236 14 24 1535 14 1196 101 209 236 14 24 1780 15 1080 101 209 236 14 24 1664 16 1007 101 209 303 14 24 1659 17 1085 101 209 303 14 24 1736 18 1139 101 209 303 14 24 1790 19 1074 101 209 303 14 24 1726 Average Average Avg yr 11- Avg yr 16- 20 yr yr 6-10 15 20 Total 20 yr 1-5 227 630 998 1126 14912 1326 101 101 101 101 2017 101 209 209 209 209 4185 209 118 185 236 303 4212 303 14 14 14 14 282 14 24 24 24 24 480 24 694 1164 1583 1778 26088 1978

Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 3790 10505 16641 18771 12427 22101 1681 1681 1681 1681 1681 1681 3488 3488 3488 3488 3488 3488 1966 3089 3931 5054 3510 5054 235 235 235 235 235 235 400 400 400 400 400 400 11559 19398 26376 29629 21740 32959

D-8

Annual Project Costs


Based on 2004 dollars Includes levelized replacement costs

Turbine O&M Costs


Based on 2004 dollars Includes levelized replacement costs

2500 2000 $ / turbine 1500 1000 500 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

35000 30000 25000 20000 15000 10000 5000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

$ x 1000

Turbine Costs per kW Rated Power


Based on 2004 dollars Includes levelized replacement costs

Turbine Costs per kWh Produced


Based on 2004 dollars Includes levelized replacement costs

35 30 25 $ / kWh 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 $ / kW 20 15 10 5 0 Project Age (yr)

0.012 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total

Consumables Wage-based Labor Equipment

D-9

1500 kW model Results

Table 1. Wind Farm Operations


Capacity Factor (%) Number of Turbines Energy Sales Price ($/kw-hr.) Power Generated (MW) 35 40 0.055 60

Notes: Description:

1500 kW, var. speed, electric 80m tower

Table 2. Turbine Characteristics


Rating Power Conversion Pitch Control Hub Height 1500 Variable Speed Electric 80

Table 3. Staffing Levels and Costs


Site Manager Salary Admin. Asst. Salary Sr. Tech Wage Jr. Tech Wage Totals

Salary ($/year) Wage ($/hr) 85,000 35,000 18.00 12.00

Burden (%) 35 35 35 35

Total $ $ $ $ 114,750 47,250 24.30 16.20

years 1-5 1 2 1 3

# of Staff 6-10 1 2 1 4

11-15 1 2 2 4

16-20 1 2 2 5

Staffing Costs ($/Year) years 1-5 6-10 114,750 114,750 94,500 94,500 50,544 101,088 360,882 50,544 134,784 394,578

11-15 114,750 94,500 101,088 134,784 445,122

16-20 114,750 94,500 101,088 168,480 478,818

Table 4. Annual Turbine Consumables


Item Gear oil filter Hydraulic filter Offline-filter Hydraulic oil replenish Gear oil change (mineral) Yaw gear grease Bearing grease Oil Testing Electricity 200 100 100 20 284 120 90 120 1,314 200 100 100 20 284 120 90 120 1,314 User Values $/turbine Default Values $/turbine

Table 5. Crane Cost (+Mobilization)


Item Blade--struct. repair Blade--nonstruct. repai Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed o Generator--rot. & brgs Generator--brgs only Main Bearing Pitch Bearing Yaw Bearing User $/event 28,000 28,000 56,000 56,000 56,000 39,000 39,000 56,000 28,000 56,000 Default $/event 28,000 28,000 56,000 56,000 56,000 39,000 39,000 56,000 28,000 56,000

Table 6. Site Equipment, Supplies & Maintenance


Annual Costs ($)
User $2,500 $5,000 $8,000 $2,500 $6,000 Total Equipment $5,000 $4,100 $2,500 $1,700 $800 Default 2,500 5,000 8,000 2,500 6,000 24,000 5,000 4,100 2,500 1,700 800 14,100

Total

2,348

2,348 Total Maintenance

D-10

Table 7. Turbine Parts List Part Identification Constant Failure Rate


Failure Prediction (Constant Rate or Weibull Curve) Constant Rate Constant Rate Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Failures per 100 original parts by Year 20 5 100 5 12 12 15 12 15 3.5 2.0 1.1 3.5 2.0 10.8 10.0 10.7 10.8 12.5

Weibull Failure Rate


Mean Life (50% failures)

Repair/Replacement Costs
qty per turbine 3 3 0 3 0 0 3 3 3 Addt'l Labor to Repair / Replace (hr) 37 69 11 57 8 4 4 8 4

System Rotor

Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive

Alpha

Beta

Cost 52200 5220 1860 16700 3780 1000 4000 2030 4200

10

3.5

9.0

Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE

Parts in Project 120 120 120

120 120 120

Drivetrain

Main bearing High-speed coupling

Constant Rate Weibull Curve

5 25 3.5 22.5

1 1

13400 4091

121 12

TRUE FALSE

40 40

Gearbox and Lube

Gearbox--gear & brgs Constant Rate Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve

5 20 20 12 19 3.5 3.5 3.0 1.1 18.0 18.0 10.6 13.6

1 1 1 3 2

151900 86800 43400 1400 257

91 91 27 4 4

TRUE TRUE TRUE FALSE FALSE

40 40 40 120 80

Generator and Cooling

Generator--rot. & brgs Constant Rate Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve

5 17 15 19 20 3.5 2.0 1.1 2.0 15.3 12.5 13.6 16.7

1 2 1 2 3

52850 3300 18000 257 2620

20 10 8 4 4

TRUE TRUE FALSE FALSE FALSE

40 80 40 80 120

Brakes & Hydraulics

Brake caliper Brake Pads Accumulator Hydraulic pump Hydraulic valve

Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve

10 10 6 12 12

2.0 3.0 3.0 3.0

8.3 5.3 10.6 10.6

3 2 1 1 4

2055 200 3000 1200 120

6 0 4 4 2

FALSE FALSE FALSE FALSE FALSE

120 80 40 40 160

Yaw System

Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing

Constant Rate Weibull Curve Weibull Curve Weibull Curve

12 10 10

3.5 2.0 3.5

10.8 8.3 9.0

4 4 8 1

9359 250 400 6853

8 8 8 121

FALSE FALSE FALSE TRUE

160 160 320 40

Control System

Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic

Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve

15 15 15 14 12

2.0 2.0 2.0 2.0 2.0

12.5 12.5 12.5 11.7 10.0

1 1 2 17 2

4700 6000 1200 300 1200

0 0 0 0 0

FALSE FALSE FALSE FALSE FALSE

40 40 80 680 80

Electrical and Grid

Main Contactor Main Circuit Breaker Soft starter

Weibull Curve Weibull Curve Weibull Curve

20 30 30

2.0 2.0 2.0

16.7 25.0 25.0

1 1 0

7980 8687 5369

4 4 8

FALSE FALSE FALSE

40 40

Misc. (All others)

Miscellaneous Parts

Constant Rate

94810

FALSE

40

D-11

1500 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 1500 Electric Variable Speed 40 60 0.35 Project Parts Cost Breakdown Parts 10,421,675 Crane 6,575,400 Additional Labor 518531 Total 17,515,606 Gross Project Income / yr $10,117,800 Gross Turbine Income / yr $252,945 Annual Production (MW-hr) $183,960

Total Project O&M Cost ($000) Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /Turbine Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kW Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kWh Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total 1 0.001 0.001 0.001 0.001 0.000 0.000 0.003 2 0.001 0.001 0.001 0.001 0.000 0.000 0.004 3 0.001 0.001 0.001 0.001 0.000 0.000 0.004 4 0.002 0.001 0.001 0.001 0.000 0.000 0.005 5 0.002 0.001 0.001 0.001 0.000 0.000 0.005 6 0.002 0.001 0.001 0.001 0.000 0.000 0.005 7 0.004 0.001 0.001 0.001 0.000 0.000 0.007 8 0.003 0.001 0.001 0.001 0.000 0.000 0.005 9 0.004 0.001 0.001 0.001 0.000 0.000 0.007 10 0.007 0.001 0.001 0.001 0.000 0.000 0.010 11 0.006 0.001 0.001 0.001 0.000 0.000 0.009 12 0.006 0.001 0.001 0.001 0.000 0.000 0.009 13 0.005 0.001 0.001 0.001 0.000 0.000 0.008 14 0.008 0.001 0.001 0.001 0.000 0.000 0.011 15 0.007 0.001 0.001 0.001 0.000 0.000 0.010 16 0.008 0.001 0.001 0.001 0.000 0.000 0.011 17 0.007 0.001 0.001 0.001 0.000 0.000 0.010 18 0.008 0.001 0.001 0.001 0.000 0.000 0.011 19 0.008 0.001 0.001 0.001 0.000 0.000 0.011 1 2.2 1.6 3.5 2.5 0.2 0.4 10.5 2 3.3 1.6 3.5 2.5 0.2 0.4 11.5 3 3.9 1.6 3.5 2.5 0.2 0.4 12.1 4 5.6 1.6 3.5 2.5 0.2 0.4 13.8 5 6.0 1.6 3.5 2.5 0.2 0.4 14.3 6 6.1 1.6 3.5 3.1 0.2 0.4 14.8 7 12.8 1.6 3.5 3.1 0.2 0.4 21.5 8 7.9 1.6 3.5 3.1 0.2 0.4 16.7 9 13.3 1.6 3.5 3.1 0.2 0.4 22.1 10 21.9 1.6 3.5 3.1 0.2 0.4 30.7 11 18.5 1.6 3.5 3.9 0.2 0.4 28.1 12 19.2 1.6 3.5 3.9 0.2 0.4 28.8 13 15.7 1.6 3.5 3.9 0.2 0.4 25.3 14 25.1 1.6 3.5 3.9 0.2 0.4 34.8 15 20.5 1.6 3.5 3.9 0.2 0.4 30.1 16 23.8 1.6 3.5 4.5 0.2 0.4 33.9 17 21.5 1.6 3.5 4.5 0.2 0.4 31.7 18 24.7 1.6 3.5 4.5 0.2 0.4 34.9 19 23.8 1.6 3.5 4.5 0.2 0.4 34.0 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 4.2 12.4 19.8 24.1 15.13 26.7 1.6 1.6 1.6 1.6 1.57 1.6 3.5 3.5 3.5 3.5 3.49 3.5 2.5 3.1 3.9 4.5 3.51 4.5 0.2 0.2 0.2 0.2 0.24 0.2 0.4 0.4 0.4 0.4 0.40 0.4 12.4 21.2 29.4 34.3 24.33 36.9 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 0.00 0.00 0.01 0.01 0.00 0.009 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.000 0.000 0.012 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 1 3360 2348 5231 3791 353 600 15683 2 4922 2348 5231 3791 353 600 17245 3 5878 2348 5231 3791 353 600 18200 4 8443 2348 5231 3791 353 600 20766 5 9065 2348 5231 3791 353 600 21387 6 9081 2348 5231 4633 353 600 22246 7 19135 2348 5231 4633 353 600 32300 8 11880 2348 5231 4633 353 600 25045 9 19969 2348 5231 4633 353 600 33134 10 32875 2348 5231 4633 353 600 46040 11 27721 2348 5231 5897 353 600 42150 12 28781 2348 5231 5897 353 600 43210 13 23540 2348 5231 5897 353 600 37968 14 37700 2348 5231 5897 353 600 52129 15 30735 2348 5231 5897 353 600 45164 16 35646 2348 5231 6739 353 600 50917 17 32309 2348 5231 6739 353 600 47580 18 37060 2348 5231 6739 353 600 52331 19 35730 2348 5231 6739 353 600 51001 1 134 94 209 152 14 24 627 2 197 94 209 152 14 24 690 3 235 94 209 152 14 24 728 4 338 94 209 152 14 24 831 5 363 94 209 152 14 24 855 6 363 94 209 185 14 24 890 7 765 94 209 185 14 24 1292 8 475 94 209 185 14 24 1002 9 799 94 209 185 14 24 1325 10 1315 94 209 185 14 24 1842 11 1109 94 209 236 14 24 1686 12 1151 94 209 236 14 24 1728 13 942 94 209 236 14 24 1519 14 1508 94 209 236 14 24 2085 15 1229 94 209 236 14 24 1807 16 1426 94 209 270 14 24 2037 17 1292 94 209 270 14 24 1903 18 1482 94 209 270 14 24 2093 19 1429 94 209 270 14 24 2040 Average Average Avg yr 11- Avg yr 16- 20 yr yr 6-10 15 20 Total 20 yr 1-5 253 744 1188 1446 18154 1601 94 94 94 94 1879 94 209 209 209 209 209 4185 152 185 236 270 4212 270 14 14 14 14 282 14 24 24 24 24 480 24 746 1270 1765 2057 29192 2212

Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 6333 18588 29695 36154 22693 40027 2348 2348 2348 2348 2348 2348 5231 5231 5231 5231 5231 5231 3791 4633 5897 6739 5265 6739 353 353 353 353 353 353 600 600 600 600 600 600 18656 31753 44124 51426 36490 55299

D-12

Annual Project Costs


Based on 2004 dollars Includes levelized replacement costs

Turbine O&M Costs


Based on 2004 dollars Includes levelized replacement costs

2500

60000 50000

2000 $ x 1000 / yr $ / turbine / yr 40000 30000 20000 10000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)

1500

1000

500

0 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total

Consumables Wage-based Labor Equipment

Turbine Costs per kW Rated Power


Based on 2004 dollars Includes levelized replacement costs

Turbine Costs per kWh Produced


Based on 2004 dollars Includes levelized replacement costs

40 35 30 $ / kW $ / kWh 25 20 15 10 5 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)

0.014 0.012 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)

Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total

Consumables Wage-based Labor Equipment

Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total

Consumables Wage-based Labor Equipment

D-13

2000 kW model Results

Table 1. Wind Farm Operations


Capacity Factor (%) Number of Turbines Energy Sales Price ($/kw-hr.) Power Generated (MW) 35 30 0.055 60

Notes: Description:

2000 kw, variable speed, electric pitch, 80m tower

Table 2. Turbine Characteristics


Rating Power Conversion Pitch Control Hub Height 2000 Variable Speed Electric 80

Table 3. Staffing Levels and Costs


Site Manager Salary Admin. Asst. Salary Sr. Tech Wage Jr. Tech Wage Totals

Salary ($/year) Wage ($/hr) 85,000 35,000 18.00 12.00

Burden (%) 35 35 35 35

Total $ $ $ $ 114,750 47,250 24.30 16.20

years 1-5 1 2 1 2

# of Staff 6-10 1 2 1 3

11-15 1 2 1 4

16-20 1 2 2 4

Staffing Costs ($/Year) years 1-5 6-10 114,750 114,750 94,500 94,500 50,544 67,392 327,186 50,544 101,088 360,882

11-15 114,750 94,500 50,544 134,784 394,578

16-20 114,750 94,500 101,088 134,784 445,122

Table 4. Annual Turbine Consumables


Item Gear oil filter Hydraulic filter Offline-filter Hydraulic oil replenish Gear oil change (mineral) Yaw gear grease Bearing grease Oil Testing Electricity 267 100 100 20 377 160 120 120 1,752 267 100 100 20 377 160 120 120 1,752 User Values $/turbine Default Values $/turbine

Table 5. Crane Cost (+Mobilization)


Item Blade--struct. repair Blade--nonstruct. repai Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed o Generator--rot. & brgs Generator--brgs only Main Bearing Pitch Bearing Yaw Bearing User $/event 33,000 33,000 69,000 69,000 69,000 48,000 48,000 69,000 33,000 69,000 Default $/event 33,000 33,000 69,000 69,000 69,000 48,000 48,000 69,000 33,000 69,000

Table 6. Site Equipment, Supplies & Maintenance


Annual Costs ($)
User $2,500 $5,000 $8,000 $2,500 $6,000 Total Equipment $5,000 $4,100 $2,500 $1,700 $800 Default 2,500 5,000 8,000 2,500 6,000 24,000 5,000 4,100 2,500 1,700 800 14,100

Total

3,015

3,015 Total Maintenance

D-14

Table 7. Turbine Parts List Part Identification Constant Failure Rate


Failure Prediction (Constant Rate or Weibull Curve) Constant Rate Constant Rate Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve Failures per 100 original parts by Year 20 5 100 5 12 12 15 12 15 3.5 2.0 1.1 3.5 2.0 10.8 10.0 10.7 10.8 12.5

Weibull Failure Rate


Mean Life (50% failures)

Repair/Replacement Costs
Addt'l Labor to Repair / Replace (hr) 43 76 14 63 8 4 4 10 4

System Rotor

Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive

Alpha

Beta

10

3.5

9.0

qty per turbine 3 3 0 3 0 0 3 3 3

Cost 70650 7065 2130 23700 3780 1000 5333 2707 5600

Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE

Parts in Project 90 90 90

90 90 90

Drivetrain

Main bearing High-speed coupling

Constant Rate Weibull Curve

5 25 3.5 22.5

1 1

21000 5455

134 12

TRUE FALSE

30 30

Gearbox and Lube

Constant Rate Gearbox--gear & brgs Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve

5 20 20 12 19 3.5 3.5 3.0 1.1 18.0 18.0 10.6 13.6

1 1 1 3 3

216020 123440 61720 1600 257

104 104 37 4 4

TRUE TRUE TRUE FALSE FALSE

30 30 30 90 90

Generator and Cooling

Constant Rate Generator--rot. & brgs Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve

5 17 15 19 20 3.5 2.0 1.1 2.0 15.3 12.5 13.6 16.7

1 2 1 3 3

76860 4400 18000 257 3820

22 10 8 4 4

TRUE TRUE FALSE FALSE FALSE

30 60 30 90 90

Brakes & Hydraulics

Brake caliper Brake Pads Accumulator Hydraulic pump Hydraulic valve

Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve

10 10 6 12 12

2.0 3.0 3.0 3.0

8.3 5.3 10.6 10.6

4 4 1 1 5

2250 200 5100 1200 120

6 0 4 4 2

FALSE FALSE FALSE FALSE FALSE

120 120 30 30 150

Yaw System

Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing

Constant Rate Weibull Curve Weibull Curve Weibull Curve

12 10 10

3.5 2.0 3.5

10.8 8.3 9.0

4 4 8 1

12481 250 400 9863

8 8 8 134

FALSE FALSE FALSE TRUE

120 120 240 30

Control System

Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic

Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve

15 15 15 14 12

2.0 2.0 2.0 2.0 2.0

12.5 12.5 12.5 11.7 10.0

1 1 2 25 2

6300 8100 1620 410 1200

0 0 0 0 0

FALSE FALSE FALSE FALSE FALSE

30 30 60 750 60

Electrical and Grid

Main Contactor Main Circuit Breaker Soft starter

Weibull Curve Weibull Curve Weibull Curve

20 30 30

2.0 2.0 2.0

16.7 25.0 25.0

1 1 0

11760 18074 6783

4 4 8

FALSE FALSE FALSE

30 30

Misc. (All others)

Miscellaneous Parts

Constant Rate

126410

FALSE

30

D-15

2000 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 2000 Electric Variable Speed 30 60 0.35 Project Parts Cost Breakdown Parts 10,607,932 Crane 6,012,450 Additional Labor 426883 Total 17,047,265 Gross Project Income / yr $10,117,800 Gross Turbine Income / yr $337,260 Annual Production (MW-hr) $183,960

Total Project O&M Cost ($000) Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /Turbine Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kW Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kWh Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total 1 0.001 0.000 0.001 0.001 0.000 0.000 0.003 2 0.001 0.000 0.001 0.001 0.000 0.000 0.003 3 0.001 0.000 0.001 0.001 0.000 0.000 0.004 4 0.002 0.000 0.001 0.001 0.000 0.000 0.004 5 0.002 0.000 0.001 0.001 0.000 0.000 0.005 6 0.002 0.000 0.001 0.001 0.000 0.000 0.005 7 0.004 0.000 0.001 0.001 0.000 0.000 0.007 8 0.003 0.000 0.001 0.001 0.000 0.000 0.005 9 0.005 0.000 0.001 0.001 0.000 0.000 0.008 10 0.005 0.000 0.001 0.001 0.000 0.000 0.007 11 0.005 0.000 0.001 0.001 0.000 0.000 0.008 12 0.005 0.000 0.001 0.001 0.000 0.000 0.008 13 0.005 0.000 0.001 0.001 0.000 0.000 0.008 14 0.011 0.000 0.001 0.001 0.000 0.000 0.014 15 0.007 0.000 0.001 0.001 0.000 0.000 0.010 16 0.006 0.000 0.001 0.001 0.000 0.000 0.009 17 0.007 0.000 0.001 0.001 0.000 0.000 0.010 18 0.008 0.000 0.001 0.001 0.000 0.000 0.011 19 0.007 0.000 0.001 0.001 0.000 0.000 0.010 1 1.8 1.5 3.5 2.0 0.2 0.4 9.4 2 3.0 1.5 3.5 2.0 0.2 0.4 10.6 3 3.6 1.5 3.5 2.0 0.2 0.4 11.2 4 4.7 1.5 3.5 2.0 0.2 0.4 12.3 5 7.3 1.5 3.5 2.0 0.2 0.4 14.9 6 6.8 1.5 3.5 2.5 0.2 0.4 14.9 7 12.0 1.5 3.5 2.5 0.2 0.4 20.1 8 8.4 1.5 3.5 2.5 0.2 0.4 16.5 9 15.3 1.5 3.5 2.5 0.2 0.4 23.5 10 14.8 1.5 3.5 2.5 0.2 0.4 22.9 11 14.9 1.5 3.5 3.1 0.2 0.4 23.6 12 16.2 1.5 3.5 3.1 0.2 0.4 24.9 13 16.2 1.5 3.5 3.1 0.2 0.4 24.9 14 32.8 1.5 3.5 3.1 0.2 0.4 41.5 15 21.1 1.5 3.5 3.1 0.2 0.4 29.8 16 17.3 1.5 3.5 3.9 0.2 0.4 26.9 17 22.1 1.5 3.5 3.9 0.2 0.4 31.7 18 24.6 1.5 3.5 3.9 0.2 0.4 34.1 19 22.0 1.5 3.5 3.9 0.2 0.4 31.6 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 4.1 11.4 20.2 21.5 14.32 21.6 1.5 1.5 1.5 1.5 1.51 1.5 3.5 3.5 3.5 3.5 3.49 3.5 2.0 2.5 3.1 3.9 2.88 3.9 0.2 0.2 0.2 0.2 0.24 0.2 0.4 0.4 0.4 0.4 0.40 0.4 11.7 19.6 28.9 31.1 22.83 31.2 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 0.00 0.00 0.01 0.01 0.00 0.007 0.000 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.000 0.000 0.010 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 1 3667 3015 6975 3931 470 800 18858 2 5923 3015 6975 3931 470 800 21114 3 7228 3015 6975 3931 470 800 22419 4 9341 3015 6975 3931 470 800 24532 5 14655 3015 6975 3931 470 800 29846 6 13547 3015 6975 5054 470 800 29862 7 23910 3015 6975 5054 470 800 40224 8 16714 3015 6975 5054 470 800 33029 9 30664 3015 6975 5054 470 800 46979 10 29520 3015 6975 5054 470 800 45835 11 29748 3015 6975 6178 470 800 47186 12 32303 3015 6975 6178 470 800 49741 13 32425 3015 6975 6178 470 800 49863 14 65597 3015 6975 6178 470 800 83035 15 42223 3015 6975 6178 470 800 59661 16 34639 3015 6975 7862 470 800 53762 17 44211 3015 6975 7862 470 800 63334 18 49152 3015 6975 7862 470 800 68275 19 44062 3015 6975 7862 470 800 63184 1 110 90 209 118 14 24 566 2 178 90 209 118 14 24 633 3 217 90 209 118 14 24 673 4 280 90 209 118 14 24 736 5 440 90 209 118 14 24 895 6 406 90 209 152 14 24 896 7 717 90 209 152 14 24 1207 8 501 90 209 152 14 24 991 9 920 90 209 152 14 24 1409 10 886 90 209 152 14 24 1375 11 892 90 209 185 14 24 1416 12 969 90 209 185 14 24 1492 13 973 90 209 185 14 24 1496 14 1968 90 209 185 14 24 2491 15 1267 90 209 185 14 24 1790 16 1039 90 209 236 14 24 1613 17 1326 90 209 236 14 24 1900 18 1475 90 209 236 14 24 2048 19 1322 90 209 236 14 24 1896 Average Average Avg yr 11- Avg yr 16- 20 yr yr 6-10 15 20 Total 20 yr 1-5 245 686 1214 1292 17183 1297 90 90 90 90 1809 90 209 209 209 209 4185 209 118 152 185 236 3454 236 14 14 14 14 282 14 24 24 24 24 480 24 701 1176 1737 1865 27393 1870

Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 8163 22871 40459 43058 28638 43224 3015 3015 3015 3015 3015 3015 6975 6975 6975 6975 6975 6975 3931 5054 6178 7862 5756 7862 470 470 470 470 470 470 800 800 800 800 800 800 23354 39186 57897 62180 45654 62346

D-16

Annual Project Costs


Based on 2004 dollars Includes levelized replacement costs

Turbine O&M Costs


Based on 2004 dollars Includes levelized replacement costs

3000 2500 $ / turbine / yr 2000 $ x 1000 / yr 1500 1000 500 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

90000 80000 70000 60000 50000 40000 30000 20000 10000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)

Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total

Consumables Wage-based Labor Equipment

Turbine Costs per kW Rated Power


Based on 2004 dollars Includes levelized replacement costs

Turbine Costs per kWh Produced


Based on 2004 dollars Includes levelized replacement costs

45 40 35 30 $ / kW 25 20 15 10 5 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) $ / kWh

0.016 0.014 0.012 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)

Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total

Consumables Wage-based Labor Equipment

Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total

Consumables Wage-based Labor Equipment

D-17

2500 kW model Results


Comparison Study 2500 kW
Table 1. Wind Farm Operations
Capacity Factor (%) Number of Turbines Energy Sales Price ($/kw-hr.) Power Generated (MW) 35 24 0.055 60 Notes: Description: 2500 kw, variable speed, electric pitch, 80m tower

Table 2. Turbine Characteristics


Rating Power Conversion Pitch Control Hub Height 2500 Variable Speed Electric 80

Table 3. Staffing Levels and Costs


Site Manager Salary Admin. Asst. Salary Sr. Tech Wage Jr. Tech Wage Totals

Salary ($/year) Wage ($/hr) 85,000 35,000 18.00 12.00

Burden (%) 35 35 35 35

Total $ $ $ $ 114,750 47,250 24.30 16.20

years 1-5 1 2 1 2

# of Staff 6-10 1 2 1 2

11-15 1 2 1 3

16-20 1 2 1 4

Staffing Costs ($/Year) years 1-5 6-10 11-15 114,750 114,750 114,750 94,500 94,500 94,500 50,544 50,544 50,544 67,392 67,392 101,088 327,186 327,186 360,882

16-20 114,750 94,500 50,544 134,784 394,578

Table 4. Annual Turbine Consumables


Item Gear oil filter Hydraulic filter Offline-filter Hydraulic oil replenish Gear oil change (mineral) Yaw gear grease Bearing grease Oil Testing Electricity User Values $/turbine 333 100 100 20 469 200 150 120 2,190 Default Values $/turbine 333 100 100 20 469 200 150 120 2,190

Table 5. Crane Cost (+Mobilization)


User Item $/event Blade--struct. repair 39,000 39,000 Blade--nonstruct. repai 84,000 Gearbox--gear & brgs 84,000 Gearbox--brgs, all 84,000 Gearbox--high speed o 60,000 Generator--rot. & brgs 60,000 Generator--brgs only 84,000 Main Bearing 39,000 Pitch Bearing 84,000 Yaw Bearing Default $/event 39,000 39,000 84,000 84,000 84,000 60,000 60,000 84,000 39,000 84,000

Table 6. Site Equipment, Supplies & Maintenance


Annual Costs ($)
User $2,500 $5,000 $8,000 $2,500 $6,000 Total Equipment $5,000 $4,100 $2,500 $1,700 $800 Total Maintenance 2,500 5,000 8,000 2,500 6,000 24,000 5,000 4,100 2,500 1,700 800 14,100 Default 2,500 5,000 8,000 2,500 7,400 25,400 8,100 6,700 4,000 2,700 1,300 22,800

Total

3,683

3,683

D-18

Table 7. Turbine Parts List Part Identification Constant Failure Rate


Failures per Failure 100 original Prediction (Constant Rate or parts by Year 20 Weibull Curve) Constant Rate 5 Constant Rate 100 Weibull Curve Weibull Curve 5 Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve

Weibull Failure Rate


Mean Life (50% failures)

Repair/Replacement Costs
Addt'l Labor to Repair / Replace (hr) 49 82 17 69 8 4 4 11 4

System Rotor

Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive

Alpha

Beta

10 12 12 15 12 15

3.5 3.5 2.0 1.1 3.5 2.0

9.0 10.8 10.0 10.7 10.8 12.5

qty per turbine 3 3 0 3 0 0 3 3 3

Cost 89150 8915 2400 30700 3780 1000 6667 3383 7000

Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE

MTTR (days) 3 3 0 3 0 0 3 3 3

Drivetrain

Main bearing High-speed coupling

Constant Rate Weibull Curve

5 25 3.5 22.5

1 1

29800 6818

147 12

TRUE FALSE

1 1

Gearbox and Lube

Gearbox--gear & brgs Constant Rate Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve

5 20 20 12 19 3.5 3.5 3.0 1.1 18.0 18.0 10.6 13.6

1 1 1 3 3

283850 162200 81100 1900 257

117 117 46 4 4

TRUE TRUE TRUE FALSE FALSE

1 1 1 3 1

Generator and Cooling

Generator--rot. & brgs Constant Rate Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve

5 17 15 19 20 3.5 2.0 1.1 2.0 15.3 12.5 13.6 16.7

1 2 1 3 3

100870 5500 18000 257 5010

24 10 8 4 4

TRUE TRUE FALSE FALSE FALSE

1 2 1 1 3

Brakes & Hydraulics

Brake caliper Brake Pads Accumulator Hydraulic pump Hydraulic valve

Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve

10 10 6 12 12

2.0 3.0 3.0 3.0

8.3 5.3 10.6 10.6

4 4 1 1 5

2445 200 7700 1200 120

6 0 4 4 2

FALSE FALSE FALSE FALSE FALSE

2 2 1 1 3

Yaw System

Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing

Constant Rate Weibull Curve Weibull Curve Weibull Curve

12 10 10

3.5 2.0 3.5

10.8 8.3 9.0

4 4 8 1

15603 250 400 13083

8 8 8 147

FALSE FALSE FALSE TRUE

2 2 4 1

Control System

Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic

Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve

15 15 15 14 12

2.0 2.0 2.0 2.0 2.0

12.5 12.5 12.5 11.7 10.0

1 1 2 25 2

7850 10200 2040 520 1200

0 0 0 0 0

FALSE FALSE FALSE FALSE FALSE

1 1 4 7 4

Electrical and Grid

Main Contactor Main Circuit Breaker Soft starter

Weibull Curve Weibull Curve Weibull Curve

20 30 30

2.0 2.0 2.0

16.7 25.0 25.0

1 1 0

15540 31920 8190

4 4 8

FALSE FALSE FALSE

1 1 0

Misc. (All others)

Miscellaneous Parts

Constant Rate

158010

FALSE

D-19

2500 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 2500 Electric Variable Speed 24 60 0.35 Project Parts Cost Breakdown Parts 10,569,218 Crane 5,893,350 Additional Labor 360004 Total 16,822,571 Gross Project Income / yr ######## Gross Turbine Income / yr Annual Production (MW-hr) $421,575 183,960

Total Project $000 /year Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total $ /Turbine /year Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total $ /kW/ year Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total $ /kW-hr Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total

1 99 88 209 118 14 24 552

2 166 88 209 118 14 24 620

3 219 88 209 118 14 24 672

4 271 88 209 118 14 24 725

5 314 88 209 118 14 24 768

6 490 88 209 118 14 24 944

7 403 88 209 118 14 24 857

8 877 88 209 118 14 24 1330

9 448 88 209 118 14 24 902

10 1027 88 209 118 14 24 1481

11 913 88 209 152 14 24 1400

12 1159 88 209 152 14 24 1646

13 1053 88 209 152 14 24 1541

14 1037 88 209 152 14 24 1524

15 1097 88 209 152 14 24 1584

16 1486 88 209 185 14 24 2007

17 2307 88 209 185 14 24 2828

18 1032 88 209 185 14 24 1553

19 1455 88 209 185 14 24 1976

20 Average yAverage yAvg yr 11-Avg yr 161089 214 649 1052 1474 88 88 88 88 88 209 209 209 209 209 185 118 118 152 185 14 14 14 14 14 24 24 24 24 24 1610 667 1103 1539 1995

1 4113 3683 8719 4914 588 1000 23016

2 6917 3683 8719 4914 588 1000 25820

3 9113 3683 8719 4914 588 1000 28016

4 11304 3683 8719 4914 588 1000 30207

5 13078 3683 8719 4914 588 1000 31981

6 20427 3683 8719 4914 588 1000 39330

7 16803 3683 8719 4914 588 1000 35706

8 36526 3683 8719 4914 588 1000 55429

9 18678 3683 8719 4914 588 1000 37581

10 42792 3683 8719 4914 588 1000 61695

11 38034 3683 8719 6318 588 1000 58340

12 48283 3683 8719 6318 588 1000 68589

13 43884 3683 8719 6318 588 1000 64191

14 43188 3683 8719 6318 588 1000 63495

15 45697 3683 8719 6318 588 1000 66003

16 61900 3683 8719 7722 588 1000 83611

17 96119 3683 8719 7722 588 1000 117830

18 43014 3683 8719 7722 588 1000 64725

19 60612 3683 8719 7722 588 1000 82323

20 Average yAverage yAvg yr 11-Avg yr 1645368 8905 27045 43817 61403 3683 3683 3683 3683 3683 8719 8719 8719 8719 8719 7722 4914 4914 6318 7722 588 588 588 588 588 1000 1000 1000 1000 1000 67079 27808 45948 64124 83113

1 1.6 1.5 3.5 2.0 0.2 0.4 9.2

2 2.8 1.5 3.5 2.0 0.2 0.4 10.3

3 3.6 1.5 3.5 2.0 0.2 0.4 11.2

4 4.5 1.5 3.5 2.0 0.2 0.4 12.1

5 5.2 1.5 3.5 2.0 0.2 0.4 12.8

6 8.2 1.5 3.5 2.0 0.2 0.4 15.7

7 6.7 1.5 3.5 2.0 0.2 0.4 14.3

8 14.6 1.5 3.5 2.0 0.2 0.4 22.2

9 7.5 1.5 3.5 2.0 0.2 0.4 15.0

10 17.1 1.5 3.5 2.0 0.2 0.4 24.7

11 15.2 1.5 3.5 2.5 0.2 0.4 23.3

12 19.3 1.5 3.5 2.5 0.2 0.4 27.4

13 17.6 1.5 3.5 2.5 0.2 0.4 25.7

14 17.3 1.5 3.5 2.5 0.2 0.4 25.4

15 18.3 1.5 3.5 2.5 0.2 0.4 26.4

16 24.8 1.5 3.5 3.1 0.2 0.4 33.4

17 38.4 1.5 3.5 3.1 0.2 0.4 47.1

18 17.2 1.5 3.5 3.1 0.2 0.4 25.9

19 24.2 1.5 3.5 3.1 0.2 0.4 32.9

20 Average yAverage yAvg yr 11-Avg yr 1618.1 3.6 10.8 17.5 24.6 1.5 1.5 1.5 1.5 1.5 3.5 3.5 3.5 3.5 3.5 3.1 2.0 2.0 2.5 3.1 0.2 0.2 0.2 0.2 0.2 0.4 0.4 0.4 0.4 0.4 26.8 11.1 18.4 25.6 33.2

1 0.0005 0.0005 0.0011 0.0006 0.0001 0.0001 0.0030

2 0.0009 0.0005 0.0011 0.0006 0.0001 0.0001 0.0034

3 0.0012 0.0005 0.0011 0.0006 0.0001 0.0001 0.0037

4 0.0015 0.0005 0.0011 0.0006 0.0001 0.0001 0.0039

5 0.0017 0.0005 0.0011 0.0006 0.0001 0.0001 0.0042

6 0.0027 0.0005 0.0011 0.0006 0.0001 0.0001 0.0051

7 0.0022 0.0005 0.0011 0.0006 0.0001 0.0001 0.0047

8 0.0048 0.0005 0.0011 0.0006 0.0001 0.0001 0.0072

9 0.0024 0.0005 0.0011 0.0006 0.0001 0.0001 0.0049

10 0.0056 0.0005 0.0011 0.0006 0.0001 0.0001 0.0080

11 0.0050 0.0005 0.0011 0.0008 0.0001 0.0001 0.0076

12 0.0063 0.0005 0.0011 0.0008 0.0001 0.0001 0.0089

13 0.0057 0.0005 0.0011 0.0008 0.0001 0.0001 0.0084

14 0.0056 0.0005 0.0011 0.0008 0.0001 0.0001 0.0083

15 0.0060 0.0005 0.0011 0.0008 0.0001 0.0001 0.0086

16 0.0081 0.0005 0.0011 0.0010 0.0001 0.0001 0.0109

17 0.0125 0.0005 0.0011 0.0010 0.0001 0.0001 0.0154

18 0.0056 0.0005 0.0011 0.0010 0.0001 0.0001 0.0084

19 0.0079 0.0005 0.0011 0.0010 0.0001 0.0001 0.0107

20 Average yAverage yAvg yr 11-Avg yr 160.0059 0.0012 0.0035 0.0057 0.0080 0.0005 0.0005 0.0005 0.0005 0.0005 0.0011 0.0011 0.0011 0.0011 0.0011 0.0010 0.0006 0.0006 0.0008 0.0010 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0088 0.0036 0.0060 0.0084 0.0108

D-20

Annual Project Costs


Based on 2004 dollars Includes levelized replacement costs

Turbine O&M Costs


Based on 2004 dollars Includes levelized replacement costs

2000 1800 1600 1400 $ x 1000 / yr 1200 1000 800 600 400 200 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total $ / turbine / yr

140000 120000 100000 80000 60000 40000 20000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

Turbine Costs per kW Rated Power


Based on 2004 dollars Includes levelized replacement costs

Turbine Costs per kW Rated Power


Based on 2004 dollars Includes levelized replacement costs

50 45 40 35 30 $ / kW 25 20 15 10 5 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

0.018 0.016 0.014 0.012 $ / kW 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment

D-21

REPORT DOCUMENTATION PAGE

Form Approved OMB No. 0704-0188

The public reporting burden for this collection of information is estimated to average 1 hour per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing the burden, to Department of Defense, Executive Services and Communications Directorate (0704-0188). Respondents should be aware that notwithstanding any other provision of law, no person shall be subject to any penalty for failing to comply with a collection of information if it does not display a currently valid OMB control number.

PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION. 1. REPORT DATE (DD-MM-YYYY) 2. REPORT TYPE

3.

DATES COVERED (From - To)

January 2008
4. TITLE AND SUBTITLE

Subcontract report

7/20/04 - 6/30/08
5a. CONTRACT NUMBER

Development of an Operations and Maintenance Cost Model to Identify Cost of Energy Savings for Low Wind Speed Turbines: July 20, 2004 June 30, 2008

DE-AC36-99-GO10337
5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6.

AUTHOR(S)

5d. PROJECT NUMBER

R. Poore and C. Walford

NREL/SR-500-40581
5e. TASK NUMBER

WER6.0301
5f. WORK UNIT NUMBER

7.

PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

8.

Global Energy Concepts, LLC Seattle, Washington


9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

PERFORMING ORGANIZATION REPORT NUMBER

YAM-4-33200-07
10. SPONSOR/MONITOR'S ACRONYM(S)

National Renewable Energy Laboratory 1617 Cole Blvd. Golden, CO 80401-3393


12. DISTRIBUTION AVAILABILITY STATEMENT

NREL
11. SPONSORING/MONITORING AGENCY REPORT NUMBER

NREL/SR-500-40581 National Technical Information Service U.S. Department of Commerce 5285 Port Royal Road Springfield, VA 22161
13. SUPPLEMENTARY NOTES

NREL Technical Monitor: Walt Musial


14. ABSTRACT (Maximum 200 Words)

The report describes the operatons and maintenance cost model developed by Global Energy Concepts under contract to NREL to estimate the O&M costs for commercial wind turbine generator facilities.

15. SUBJECT TERMS

wind energy generation; wind turbine; economic model; wind energy


16. SECURITY CLASSIFICATION OF:
a. REPORT b. ABSTRACT c. THIS PAGE 17. LIMITATION 18. NUMBER OF ABSTRACT OF PAGES 19a. NAME OF RESPONSIBLE PERSON

Unclassified

Unclassified

Unclassified

UL

19b. TELEPHONE NUMBER (Include area code) Standard Form 298 (Rev. 8/98)
Prescribed by ANSI Std. Z39.18

F1146-E(09/2007)

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