National Renewable Energy Laboratory 

Innovation for Our Energy Future 

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

Office of Energy Efficiency & Renewable Energy

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

Technical Report 

NREL/TP-500-37505 

June 2005 

Low Wind Speed 

Technologies Annual Turbine 

Technology Update (ATTU) 

Process for Land-Based, 

Utility-Class Technologies 

S. Schreck and A. Laxson 
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

Technical Report 

NREL/TP-500-37505 

June 2005 

Low Wind Speed 

Technologies Annual Turbine 

Technology Update (ATTU) 

Process for Land-Based, 

Utility-Class Technologies 

S. Schreck and A. Laxson 

Prepared under Task No. WER5.3200 
NOTICE

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iii

Table of Contents 

Cost of Energy Goal and Trends..........................................................................................1 

LWST Program Tracking and Structure..............................................................................1 

Cost of Energy Computation ...............................................................................................3 

LWST 2002 Reference Turbine...........................................................................................3 

Subcontractor COE Projection.............................................................................................4 

TIO Allocations ...................................................................................................................6 

Subcontract Work Progress and Technology Maturity Weights .........................................7 

Subcontract Weighted TIO Impact ......................................................................................9 

Aggregation of Subcontract Data.........................................................................................9 

Recapitulation of Process...................................................................................................10 

Conclusion .........................................................................................................................11 

Appendix A........................................................................................................................13 

Appendix B ........................................................................................................................22 

List of Figures 

Figure 1: LWST aggregate COE vs. FY, showing possible realization for FY08...............2 

Figure 2: LWST COE reduction by TIO, showing possible realization for FY08..............2 

Figure 3: LWST 2002 Reference Turbine ...........................................................................4 

Figure 4: LWST COE Projection Form containing typical subcontractor data..................5 

Figure 5: Schematic allocation of subcontractor COE projections to LWST TIOs ...........6 

Figure 6: Graph of typical subcontract percent completion weights ..................................7 

Figure 7: Technology maturity weights for various LWST subcontract types.................8 

Figure 8: Program-wide COE impact data aggregated by LWST TIO. ..........................10 

Figure 9: Summary of the ATTU process..........................................................................11 
iv
1

COST OF ENERGY GOAL AND TRENDS 

The objective of the Low Wind Speed Technology Project is: “By 2012, reduce the cost 

of energy (COE) for large wind systems in Class 4 winds (average wind speed of 5.8 m/s 

at 10 m height) to 3 cents/kWh (in levelized 2002 dollars) for onshore systems.” 

Thus far, competitive COE for wind energy has been achieved by focusing development 

on Class 6 sites (average wind speed of 6.7 m/s at 10 m height), and by taking advantage 

of the federal Production Tax Credit (1.8 cents/kWh in 2003 dollars). Even without the 

subsidy, current wind energy technology is such that, given favorable financing, wind 

generating plants at Class 6 sites can market electricity at prices of 4 cents/kWh or less. 

However, as more and more sites have been developed, easily accessible Class 6 sites are 

becoming scarce. In addition, many remaining Class 6 sites are located in remote areas 

that lack ready access to transmission lines. Ultimately, the scarcity of accessible Class 6 

sites may cause wind energy growth to plateau in the near future, unless improvements in 

technology can make lower wind speed sites more cost effective. 

In contrast to Class 6 sites, Class 4 wind resources in the United States are abundant and 

lie relatively near transmission lines. However, at Class 4 sites, state-of-the-art turbines 

generate electricity at 4.3-5.0 cents/kWh, which is not competitive in present domestic 

energy markets. Equally important is the fact that without significant design 

improvements, current technology appears to be incapable of reducing COE in Class 4 

resources to competitive levels. The Low Wind Speed Technologies Program is designed 

to overcome these limitations through research and development aimed at evolving cost 

competitive technologies specifically suited to Class 4 resource environments. 

LWST PROGRAM TRACKING AND STRUCTURE 

To guide wind technology development, the LWST Program quantitatively characterizes 

program direction and progress via two complementary analysis methodologies. The first 

is undertaken in response to Administration requirements dictating that federal programs 

be quantitatively monitored to ensure adequate return to the U.S. taxpayer. This directive 

is implemented through the Office of Management and Budget (OMB), and mandates 

that the LWST Program report an aggregate COE figure at the end of each fiscal year. An 

example of these data is shown in Figure 1, which appears as it might in FY08. 

In this figure, program progress is represented by the descent of the plotted data with time 

toward the 2012 program goal of 3.0 cents/kWh. The 5.5 cents/kWh is referred to 

programmatically as the LWST Baseline. That figure was the Program’s best estimate, 

prior to performing detailed analyses, of what low wind speed technology cost at that 

time. Soon after, an analytical effort was begun to support annual tracking. The first step 

in that process was to develop a technology “reference turbine,” which now serves as the 

technology starting point for LWST analyses. The COE of that reference turbine was 

determined to be 4.8 cents/kWh, as shown in Figure 1. 
2

Figure 1. LWST aggregate COE vs. FY, showing possible realization for FY08. 

The second analysis methodology is carried out as a guide to multi-year program 

planning and portfolio balancing. Reductions in aggregate program COE to the ultimate 

goal level will result from the combined impacts of incremental advances across several 

diverse technologies. Industry partners have identified a variety of technology and 

hardware approaches that could aid in reducing cost of energy, and have proposed to 

pursue these changes in their partnerships with DOE. The program refers to these as 

Technology Improvement Opportunities (TIOs). As the program tracks progress toward 

the COE goal, it also tracks progress against each of the TIOs, as shown in Figure 2. 

Figure 2. LWST COE reduction by TIO, showing possible realization for FY08. 
3

Together, these two complementary analysis methodologies comprise a COE 

computation process termed the Annual Turbine Technology Update (ATTU). This 

ATTU process is documented below, as are the associated input and output data formats. 

COST OF ENERGY COMPUTATION 

Consistent with the DOE Wind Program, the ATTU employs a cash flow financial 

representation to calculate cost of energy on a levelized basis. The changes in TCC, 

BOS, LRC, O&M, and AEP are referenced to values for the LWST 2002 Reference 

Turbine (see below), and expressed as percent changes in response to LWST technology 

development accomplishments. The equation used in this method to compute COE, along 

with explanation of the variables, is shown as Equation 1. A detailed explanation of this 

methodology can be found in Appendix A. 

 (1) 

 

 

COE = Cost of Energy 

FCR = Fixed Charge Rate (11.85%, GenCo model) 

TCC = Turbine Capital Cost 

BOS = Balance of Station 

LRC = Levelized Replacement Cost 

O&M = Operations and Maintenance 

AEP = Annual Energy Production 

LWST 2002 REFERENCE TURBINE 

To enable consistent COE projections across several subcontracts involving diverse 

technologies over the life of the LWST program, a wind turbine configuration was 

chosen to function as a technology reference. The turbine configuration chosen is a 

composite turbine closely resembling the GE 1.5s Next Generation Turbine (NGT), 

which represents state-of-the-art wind technology for 2002. The Reference Turbine is 

rated at 1.5 MW, and has a three-blade, pitch controlled hub that sweeps a 70.5 m disk 

upwind of the tower. The GE 1.5 MW machine has been successfully commercialized, 

with well over 100 MW of rated capacity presently deployed, giving the Reference 

Turbine COE a high confidence level. 

 

Because the GE NGT is a commercial machine, a substantial volume of pertinent 

engineering and cost documentation was not releasable outside the National Renewable 

Energy Laboratory. To complete the Reference Turbine data set for release to LWST 

subcontractors, surrogate data were extracted or derived from closely related work 

previously accomplished under the Wind Partnerships for Advanced Component 
4

Technologies (WindPACT) Project. Once assembled, the complete reference data set 

was refined and validated using historical volume manufacturing and market data. 

Figure 3. LWST 2002 Reference Turbine 

SUBCONTRACTOR COE PROJECTIONS 

Using the LWST 2002 Reference Turbine as the point of reference, subcontractors 

annually project component level COE improvements that have accrued from their work 

during the fiscal year. Resulting subcontractor COE projections are submitted to NREL 

in time to allow the annual ATTU to be completed before the end of the fiscal year. 

Every LWST subcontractor documents their annual COE projections using the LWST 

COE Projection Form shown in Figure 4. The first column of Figure 4 lists several 

fundamental components of COE. These have been separated into categories 

corresponding to the five principal determinants of COE: 

1) Turbine capital cost (TCC) 

2) Balance of station (BOS) 

3) Levelized replacement cost (LRC) 

4) Operations and maintenance (O&M) 

5) Annual energy production (AEP) 

 1.5 MW 

 Three blades 

 Upwind 

 Pitch control 

 100 MW deployed 
5

The second column contains component contributions to COE, expressed in U.S. dollars, 

corresponding to the LWST 2002 Reference Turbine. In the third column, subcontractors 

enter COE projections based on their LWST technology advances during the fiscal year. 

For many subcontracts, projected costs will differ from LWST reference costs for only a 

small subset of the listed components. This reflects the fact that most subcontracts are 

tightly focused to reduce costs in carefully defined turbine technology areas, as integral 

parts of a balanced program portfolio. The fourth column in Figure 4 documents 

component COE improvements, expressed as percent changes to the reference data in 

column two. Finally, column five contains summary percent cost improvements for each 

of the five principal COE determinants (TCC, BOS, LRC, O&M, and AEP). 

Figure 4. LWST COE Projection Form containing typical subcontractor data. 

LWST 

Reference 

Costs

Subcontractor 

Projected 

Costs 
6

From column five of each subcontractor’s LWST COE Projection Form, values for the 

five principal COE determinants (TCC, BOS, LRC, O&M, and AEP) are extracted and 

entered into a separate ATTU Subcontractor Data Input Worksheet, an example of which 

is shown in Appendix B, in Figures B1a and B1b. These five data elements are entered 

into the spreadsheet in the locations identified as “Subcontractor COE Projection Entry”. 

TIO ALLOCATIONS 

Examination of the LWST COE Projection Form in Figure 4 shows that COE projection 

data are acquired from subcontractors in a format consistent with general turbine 

structure and function. This format is beneficial in that consistency with turbine structure 

and function provides a context within which to understand the individual data elements, 

thus minimizing ambiguity in subcontractor data submission. 

However, the ATTU must quantify the impact of LWST programmatic composition and 

process. Thus, after assimilation of subcontractor COE projection data, these projections 

are allocated across the LWST TIO categories, which were introduced in conjunction 

with Figure 2. This allocation requires understanding of both turbine 

configuration/operation as well as LWST program composition/process, and is performed 

by NREL and Sandia Subcontract Technical Monitors. 

TIO allocation values are entered into a separate ATTU Subcontractor Data Input 

Worksheet for each subcontract. An example of this worksheet is shown in Appendix B, 

in Figures B1a and B1b. TIO allocation data elements are entered into the spreadsheet in 

the locations identified as “TIO Allocation Entry”. 

TIO allocation is shown schematically in Figure 5. This figure depicts various modes in 

which subcontractor COE projections could be allocated to LWST TIO categories. The 

converging arrows represent aggregation, where subcontractor TCC and BOS 

improvements are combined into an improvement in LWST TIO 2. Alternatively, the 

diverging arrows represent apportionment of subcontractor O&M benefits between TIO 4 

and TIO 5. In some cases, the COE impact projected by the subcontractor could transfer 

directly to another LWST TIO, as shown by the single arrow between LRC and TIO 6. 

Figure 5. Schematic allocation of subcontractor COE projections to LWST TIOs. 
7

SUBCONTRACT WORK PROGRESS AND 

TECHNOLOGY MATURITY WEIGHTS 

Each LWST subcontractor’s COE projection represents the COE that the subcontractor 

estimates could be achieved, assuming their subcontract were to be completed and the 

results of their subcontract work were to be commercialized across 100 MW of wind 

generating capacity. Thus, in computing the ATTU for each fiscal year, weightings are 

applied which quantify subcontract completion and the commercialization readiness, or 

technology maturity, of the work at subcontract completion. 

The first weighting factor corresponds to the percentage of subcontract work completed. 

This percentage is arrived at by first identifying significant phases in the subcontract 

work plan, as shown for the example project documented in Figure 6. Then, incremental 

completion percentages are assigned to these phases, depending upon the magnitude of 

effort required to complete each phase. Major work phases like detailed design, 

fabrication, and testing can be expected to comprise a major percentage of the total effort. 

Figure 6. Graph of typical subcontract percent completion 

weights. Stage gate events labeled in capital letters. 

At the inception of each subcontract, NREL and Sandia Subcontract Technical Monitors 

consult the Statement of Work to identify significant work phases for the subcontract. 

These are entered into an ATTU Subcontractor Data Input Worksheet for the subcontract, 

at the location marked “Subcontractor Work Progress Entry” in Figure B1b of Appendix 

B. During the subcontract performance period, Technical Monitors ascertain work 

progress using status reports submitted periodically by the subcontractor. Completion of 

work phases are entered into the spreadsheet by replacing “0” with “1”, again in the area 

marked “Subcontractor Work Progress Entry” in Figure B1b of Appendix B. 

Immediately to the right of this area, the quantity designated “Total % Complete” 

represents the completion weighting factor used in computing the ATTU. 
8

The second weighting factor quantifies the technology maturity of the subcontract types 

encompassed by LWST, as shown in Figure 7. While commercialization and deployment 

activities are not funded under LWST, the program is structured to facilitate these 

ultimate goals. Thus, a technology maturity weight of 100 percent is reserved for LWST 

components or systems that have been successfully commercialized and deployed across 

at least 100 MW of wind generating capacity. In consistent fashion, the three types of 

LWST subcontract are assigned technology maturity weights of less than 100 percent, 

depending on the goal of the subcontract. 

Figure 7. Technology maturity weights for various LWST subcontract types. 

The first type of subcontract is for concept design studies. Concept studies offer an 

industry partner an opportunity to determine the probable value of a particular concept by 

performing a paper analysis before undertaking detailed design and fabrication. These 

small scale studies involve no cost sharing, keeping the results in the public domain. A 

technology maturity weight of 15 percent is assigned to concept studies that include 

fabrication or testing, while 10 percent is given to those culminating in a paper study. 

The second type of subcontract is a cost-shared component development project. In this 

type of project, the industry partner completes detailed design and testing of an advanced 

prototype component or subsystem. Component development subcontracts that can be 

readily employed in a retrofit or otherwise easily integrated into existing machines are 

assigned a technology maturity weight of 40 percent. Component developments aimed at 

producing more integral components of future machines, such as drive trains, are given a 

maturity weight of 30 percent. 

The third type of subcontract calls for the cost-shared detailed design, fabrication and 

field test of an advanced prototype turbine. These turbines will be tested in field 

environments to demonstrate the likelihood of achieving the LWST goal. These 

subcontracts are assigned a technology maturity weight of 60 percent. 
9

SUBCONTRACT WEIGHTED TIO IMPACT 

For each LWST subcontract, the four parameter sets explained previously and listed 

below are entered into a separate Subcontractor Data Input Worksheet (see Appendix B): 

 Subcontractor COE Projections 

 TIO Allocations 

 Subcontractor Work Progress 

 Subcontract Technology Maturity Weight 

Entering these quantities into the worksheet yields Weighted TIO Impact data in the area 

indicated on the Subcontractor Data Input Worksheet in Figure B1a, of Appendix B. 

These Weighted TIO Impact data represent improvements to TCC, BOS, LRC, O&M, 

and AEP due to impacts from the TIO categories next to which the output data are listed. 

If a subcontract was not intended to impact a given COE component via a given TIO, 

then the cell at the intersection of that COE component column and that TIO category 

row will be blank. A cell containing a value of 0.00 indicates that the subcontract was 

intended to impact the associated COE component and TIO category, but did not do so 

during the fiscal year. Consistent with other COE data, the Weighted TIO Impact data 

are expressed as percent changes referenced to COE for the LWST 2002 Reference 

Turbine. 

AGGREGATION OF SUBCONTRACT DATA 

To this point in the ATTU process, data have been entered and results obtained for each 

individual subcontract. Further processing is required to obtain program-wide COE 

impact data aggregated by LWST TIO (for portfolio assessment), and aggregated as a 

unitary value for the LWST Program (for reporting up through DOE and OMB). 

The first part of the aggregation process consists of obtaining program-wide COE impact 

data broken out according to the five COE components (TCC, BOS, LRC, O&M, and 

AEP) and the eight LWST TIO categories. Data in this format are contained in the 

Weighted TIO Impact area of the ATTU subcontractor input worksheet (example in 

Figure B1, of Appendix B). Here, the COE components correspond to columns and the 

TIO categories to rows. 

Each cell in this spreadsheet area, corresponding to one COE component impacted by one 

TIO category, is aggregated across all such spreadsheets, with each spreadsheet 

corresponding to an active LWST subcontract. Aggregation consists of averaging the 

values contained in all occupied cells, and ignoring vacant cells. This process is repeated 

sequentially for each combination of COE component and TIO category, until all cells 

have been similarly aggregated. Figure 8 contains an example of COE impact data 

aggregated by TIO, to be used in an advisory capacity for LWST portfolio evaluation and 

balancing. These data are expressed as percent changes referenced to the LWST 

Reference Turbine data. 
10

The second part of the aggregation process produces a single value of COE improvement 

for the overall LWST Program. This is accomplished using data like those contained in 

Figure 8, in conjunction with LWST Reference Turbine data and Equation 1. This COE 

improvement value is expressed in terms of cents/kWh. 

Figure 8. Program-wide COE impact data aggregated by LWST TIO. 

RECAPITULATION OF PROCESS 

The ATTU process begins with subcontractor COE projections (Figure 9, block 1 in top 

row), computed as percentages with respect to the LWST Reference and submitted to 

NREL and Sandia Subcontract Technical Monitors on an annual basis. To minimize 

ambiguity in data submission, subcontractor COE projections are formatted consistent 

with wind turbine structure and function. Technical Monitors then allocate these data 

across the LWST TIO categories (Figure 9, block 2 in top row), consistent with LWST 

programmatic composition and process. Subsequently, two weighting factors are applied 

for each subcontract (Figure 9, blocks 3 and 4 in top row). The first quantifies 

subcontractor progress, expressed as percent completion, toward meeting the goals 
11

established for the subcontract. The second accounts for technology maturity and 

commercialization readiness, assuming the subcontract has been completed. 

To this point in the ATTU process, calculations are carried out separately for each 

individual subcontract. Subsequent stages of the process aggregate individual 

subcontract data in two consecutive stages. The first stage (Σ1 in Figure 9) arrives at 

program-wide COE impact data, expressed as percent improvement, subdivided 

consistent with the five COE components (TCC, BOS, LRC, O&M, and AEP) and the 

eight LWST TIO categories. Using the data produced in the first stage, the second 

aggregation stage (Σ2 in Figure 9) yields a unitary COE improvement value for the 

LWST Program, expressed in cents/kWh. 

Figure 9. Summary of the ATTU process. Blocks containing 

Σ1 and Σ2 represent first and second parts of aggregation. 

CONCLUSION 

The Low Wind Speed Technologies Program comprises a diverse, balanced portfolio of 

industry-government partnerships structured to achieve ambitious cost of energy 

reduction goals. The Annual Turbine Technology Update has been developed to quantify 

performance-based progress toward these goals, in response to OMB reporting 

requirements and to meet internal DOE program needs for advisory data. 

The ATTU process documented herein successfully balances several crucial, though 

conflicting requirements. Process inputs recapitulate turbine structure and operation, and 

are thus receptive to industry partner performance projections. Simultaneously, the 

ATTU translates these inputs to LWST programmatic composition and process, 

responding to crucial high level department and administration directives. 
12

The methodology at the heart of the ATTU is simple, rendering it accessible for 

validation purposes and reliable in routine use. These same attributes also yield visibility 

and intelligibility for oversight and audit, thereby conferring credibility and defensibility. 

In addition, the ATTU methodology is inherently scalable, enabling it to accommodate 

the multiple subcontracts currently present in the diverse LWST portfolio, and to be 

readily expanded in the future as the LWST program continues to grow. Finally, all of 

these qualities also enable the ATTU to be updated on an annual basis, to reflect 

continual, performance-based progress toward LWST COE reduction objectives. 
13

APPENDIX A 

Cost of Energy Computation 

This attachment describes the assumptions and methods that shall be used to define and 

support the primary figure-of-merit for advanced wind turbines developed under the 

DOE/NREL Low Wind Speed Technology project. The primary figure-of-merit, Cost of 

Energy (COE), is calculated using assumed wind conditions at two "Reference Sites" and 

economic parameters associated with a hypothetical Generation Company (GenCo) 

project utilizing corporate (balance sheet) financing. The calculation method presented 

below uses formulas to approximate the results of a detailed pro forma cash flow model 

used for commercial projects. NREL’s Financial Analysis Tool for Electric Energy 

Projects (FATE2-P) was used to model a hypothetical GenCo project. In an attempt to 

standardize COE estimates, typical values for financial parameters (such as cost of capital 

and inflation rate) and fixed costs (such as insurance, property taxes and land lease) were 

chosen. These typical values reflect market conditions as of October 2001. The 

simplified calculation method presented herein provides a means to evaluate design 

alternatives on a comparative basis and develop data for NREL's wind program 

assessments. However, the method is not a reliable estimate of energy costs for planned 

or actual wind power plants. 

Assumptions 

The following assumptions shall be used to calculate the COE for two Reference Sites. 

• Reference Site #1 (Class 4): representative of the Great Plains of the United States 

 - 5.8 m/s annual average wind speed at a height of 10 m, Rayleigh distribution, 

vertical wind-shear exponent = 0.143 

• Reference Site #2 (Class 6): representative of mountain ridge lines 

 - 6.7 m/s annual average wind speed at a height of 10 m, Rayleigh distribution, 

vertical wind-shear exponent = 0.143 

• Economic parameters: constant dollar COE in January 2002 dollars 

• Fixed Charge Rate (constant dollar) = 11.85% 

• Nominal (current dollar) discount rate = 9.25% 

• Real (constant dollar) discount rate = 6.07% 

• Turbine manufacturing volume: sufficient to produce 250 turbines per year, 

assuming prior production of 150 turbines 

• Project Life = 30 years 

• Plant size = 100 MW 

• Capital Costs are in January 2002 dollars 

• Plant start date = January 2003 (construction period is one year) 

• Inflation = 3% 

• Combined federal-state tax rate = 40% 

• Land Lease Cost = $0.00108/kWh in year 2002 dollars 
14

 

Cost of Energy 

The primary figure-of-merit is the levelized cost of energy, which is to be provided in 

constant, January 2002 dollars. COE is calculated for a 100 MW (rated) wind power 

plant, with an expected life of 30 years, using the following equation: 

 COE = (FCR x ICC) + AOE 

 AEPnet

where: COE ≡ Levelized Cost of Energy ($/kWh) (constant dollar) 

FCR ≡ Fixed Charge Rate (constant dollar) = (0.1185) 

ICC ≡ Initial Capital Cost ($) 

AEPnet ≡ Net Annual Energy Production (kWh/yr) 

 AOE ≡ Annual Operating Expenses 

 ≡ LLC+ (O&M + LRC) 

 AEPnet 

 LLC ≡ Land Lease Cost 

 O&M ≡ Levelized O&M Cost 

 LRC ≡ Levelized Replacement/Overhaul Cost 

Fixed Charge Rate 

The Fixed Charge Rate is the annual amount per dollar of Initial Capital Cost needed to 

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

rate is imputed from a hypothetical project, assuming GenCo balance sheet financing, 

modeled with NREL’s FATE2-P pro forma cash flow spreadsheet model. Specifically, it 

includes construction financing, financing fees, return on debt and equity, depreciation, 

income tax, property tax and insurance. For the COE calculations, a constant dollar FCR 

= 0.1185 shall be used. The 10-year Section 45 Renewable Energy Production Tax Credit 

is not included in the Fixed Charge Rate and should not be included in the analysis. 

Initial Capital Cost 

The Initial Capital Cost is the sum of the Turbine System Cost and the Balance of Station 

Cost. Neither cost should include construction financing or financing fees, because these 

are calculated and added separately through the fixed charge rate. Neither cost should 

include a debt service reserve fund, which is assumed to be zero for balance sheet 

financing. 

The Turbine System Cost shall be supported by a tabular listing of component costs and 

weights. Costs shall be based on a manufacturing volume of 250 turbines per year, 

assuming prior production of 150 turbines. In estimating the cost of components 

manufactured in-house, assembly labor and manufacturing overhead shall be included. 
15

Thus, the stated cost should be the same as that developed in a "buy/make" analysis. The 

following breakdown of component costs shall be used. 

• Rotor assembly 

 - Blades 

 - Aerodynamic control system 

 - Rotor hub 

 - Miscellaneous costs, including labor for factory assembly of rotor components 

• Nacelle assembly 

 - Low-speed shaft, bearings and couplings 

 - Gearbox 

 - Generator 

 - Mechanical brake system 

 - Mainframe (chassis) 

 - Yaw system, including drives, dampers, brakes and bearings 

 - Nacelle cover 

 - Work platform 

 - Miscellaneous costs, including labor for factory assembly of the nacelle 

• Tower (less on-site assembly costs included in "installation" below) 

• Control and electrical systems, including labor for factory assembly 

• Shipping costs, including permits and insurance 

 • Warranty costs, including insurance 

• Mark-up, including royalties, profit and overhead not included above 

The Balance of Station Cost shall be supported by a tabular listing of the costs shown 

below. 

• Wind resource assessment and feasibility studies 

• Surveying 

• Site preparation, including roads, grading and fences 

• Electrical collection system infrastructure 

• Substation 

• Foundations for the wind turbines 

• O&M facilities and equipment 

• Receiving, installation, checkout and startup 

• Wind power plant control and monitoring equipment 

• Initial spare parts inventory 

• Permits and licenses 

• Legal counsel 

• Project management and engineering 

• Construction insurance 

 • Construction contingency 
16

Annual Operating Expenses 

Land Lease Cost 

Annual Operating Expenses include Land Lease Cost, Levelized O&M Cost, and 

Levelized Replacement/Overhaul Cost, all expressed in units of $/kWh. A levelized, 

constant-dollar land lease cost of $0.00108/kWh in year 2002 dollars shall be used. (The 

levelized, current-dollar value is $0.00146/kWh in year 2002 dollars.) This value was 

derived from a land lease term of 3% of revenues in the hypothetical GenCo case 

described. Because land lease payments are tax-deductible, the land lease cost specified 

above has already been multiplied by 60% (1 - 40%, where 40% is the combined tax 

rate). 

Levelized O&M Cost 

A component of AOE that is larger than the Land Lease Cost is O&M (Operations and 

Maintenance Cost). The O&M Cost shall include, and be supported by, a tabular listing 

of the following annual costs: 

 • Labor, parts and supplies for scheduled turbine maintenance 

 • Labor, parts and supplies for unscheduled turbine maintenance 

 • Parts and supplies for equipment and facilities maintenance 

 • Labor for administration and support 

O&M should not include the land lease payment, which was included in the step above. 

O&M should not include property tax or insurance, as these are calculated separately and 

included with the Fixed Charge Rate. Because first-year O&M Cost is very close to the 

constant-dollar levelized expense, the first year value (in 2002 dollars) shall be used as a 

reasonable approximation of the levelized value. Because the first year of operation is 

2003, if O&M cost is estimated in year 2003 dollars, it should be converted to 2002 

dollars by dividing by 1.03 (1 + the rate of inflation). Because O&M is tax deductible, 

the final O&M value should be multiplied by 60% (1 – 40%, where 40% is the combined 

federal-state tax rate). Thus, the levelized O&M Cost calculation is: 

 O&M = First Year O&M Cost (in 2002 dollars) x 0.60

 AEPnet 

Levelized Replacement/Overhaul Cost

Levelized Replacement/Overhaul Cost distributes the cost of major replacements and 

overhauls over the life of the wind turbine. This cost shall be supported by a tabular 

listing of: 

• The year in which each replacement or overhaul is required relative to the year of 

installation, and 

• Each replacement or overhaul cost including parts, supplies and labor, in current 

year dollars for the year of the replacement or overhaul 
17

Downtime during replacements and overhauls shall be included in the determination of 

overall turbine availability. In the pro forma cash flow model, one “saves” for 

replacements and overhauls with deposits to a reserve fund in the years preceding the 

maintenance event. The repair is then depreciated using a straight-line convention. 

Consequently, both of these items – the major maintenance reserve fund and the repair 

depreciation – shall be incorporated into the calculation of Levelized 

Replacement/Overhaul Costs. To account for maintenance reserve fund payments, the 

following calculations shall be performed. 

(1) Use the following equation to determine the Present Value of each stream of reserve 

fund deposits incurred for each discrete replacement and overhaul event: 

 PV(n) ≡ PVF(nmidpoint) x RC(2002) x 1.03n

 where: PV(n) ≡ Present Value of annual stream of reserve fund 

 payments for event occurring in year (n) 

PVF(nmidpoint) ≡ Present Value Factor for mid-point year of reserve 

 fund payment stream 

 = (1 + i)-nmidpoint 

i ≡ Nominal discount rate = (0.0925) 

RC(2002) ≡ Replacement/Overhaul Cost in year 2002 

 (in the formula above, 1.03n

 is an inflation factor) 

For example, if a replacement is made in year 10, the mid-point year (nmidpoint) is 5, 

because reserve fund payments are made from years 1 through 10. If second identical 

replacement follows in year 20, the mid-point year for that event is 15, because the 

reserve fund payments for that replacement were made from years 10 through 20. 

However, if replacement is made only in year 20, the mid-point year is 10. 

(2) Calculate the Levelized Replacement/Overhaul Cost (in constant dollars) by 

multiplying the sum of present values of the reserve fund payment streams by the 

Capital Recovery Factor. 

 

 LRC = CRF x ∑ PV(n) 

 

 where: CRF ≡ Capital Recovery Factor 

 ≡ iconst/(1-(1+iconst)^ -30 

= (0.073)

 iconst ≡ Constant dollar discount rate = (0.0607) 

(3) Multiply LRC by 0.80 to account for depreciation of each replacement (this factor 

was derived from the pro forma spreadsheet model described above)
18

Net Annual Energy Production 

The Net Annual Energy Production shall be calculated for two Reference Sites, using 

wind-turbine performance specifications, estimated energy losses, and turbine 

availability. AEP calculations shall be supported by a tabular listing of the parameters 

shown below. Values in parentheses shall be used for the Reference Sites. 

• Reference Site #1: annual average wind speed at a hub height of 10 m = (5.8 m/s) 

• Reference Site #2: annual average wind speed at a hub height of 10 m = (6.7 m/s) 

• Vertical wind-shear exponent = (0.143) 

• Wind distribution table or specification = (Rayleigh) 

Gross Annual Energy Production shall be calculated using the methodology described in 

the latest draft [1] of the International Electrotechnical Commission (IEC) Standard 

1400-12. For calculations of COE, the wind speed range may be divided into 1.0 m/s 

bins rather than the IEC-specified 0.5 m/s bins. The following equations shall be used. 

 N 

 AEPgross = Nh ∑ [ F(Vi) - F(Vi+1)] [(Pi + Pi+1) / 2] 

 i=1 

 where: AEPgross ≡ Gross Annual Energy Production (kWh/yr/turbine) 

 Nh ≡ Number of hours in one year 

 = (8760) 

 N ≡ Number of wind speed bins 

 Vi ≡ Wind speed in bin (i) (m/s) 

 Vi+1 ≡ Wind speed in bin (i+1) (m/s) 

 Pi ≡ Power output in bin (i) (kW) 

 Pi+1 ≡ Power output in bin (i+1) (kW) 

 F(V) ≡ Accumulated Rayleigh distribution 

 = 1+ exp [-π/4 x (V/Vhub, avg)2] 

 V ≡ Actual wind speed (m/s) 

 Vhub, avg ≡ Annual average wind speed at hub height (m/s) 

 = V10m, avg x (Hhub / 10)α

 V10m, avg ≡ Annual average wind speed at the Reference Site (m/s) 

 Hhub ≡ Hub height (m) 

 α ≡ Vertical wind shear exponent = (0.143) 

Turbine Performance shall be tabulated as electrical power output at the bus bar versus 

wind speed at hub height. The table shall show power output for wind speeds from 0 to 

25 m/s in 1.0 m/s increments starting with 0.5 m/s. If the table is based upon 
19

measurements, normalizations and averaging using the IEC methodology, it shall identify 

which bins include "measured" data (based on three, 10-minute data sets) and which bins 

are extrapolations of measured data. If the table is based on projected performance, the 

rotor configuration and analysis method (e.g. PROP) shall be clearly stated. 

Net Annual Energy Production shall account for energy losses and availability as follows. 

 AEPnet = AEPgross x (1 - EL) x Availability 

 where: EL ≡ Product of individual energy losses (% losses expressed as a decimal) 

 = 1 - (1 - Larray) x (1 - Lsoiling) x (1 - Lcontrol) x (1 - Lcollect) 

 Larray ≡ Array losses 

 Lsoiling ≡ Blade soiling losses 

 Lcontrol ≡ Controls and miscellaneous losses 

 Lcollect ≡ Collection system losses from the turbines to the substation 

Energy Losses and Availability shall be specified in a tabular listing. Availability is the 

ratio of the number of hours that the turbine was capable of operating during a certain 

period (excludes the number of hours that it could not operate because of maintenance or 

fault situations) to the total number of hours in the period. 
20

Wind Resource Regimes 

 

Using the methods described above, LWST cost-of-energy (COE) will be calculated at 

two wind regimes. The first is a Class 4 site, which has a Rayleigh distribution of wind 

speeds with a 5.8 m/s annual average at a height of 10 meters. The second is a Class 6 

site, which has a Rayleigh distribution of wind speeds with a 6.7 m/s annual average at a 

height of 10 meters. 

Percent of Time At 

Wind Speed 

Wind Speed 

Bin Center (m/s) 

Class 4 Site

5.8 m/s

Class 6 Site

6.7 m/s

Subcontractor-Selected 

Structural Design Site 

 0.5 

 1.5 

 2.5 

 3.5 

 4.5 

 5.5 

 6.5 

 7.5 

 8.5 

 9.5 

 10.5 

 11.5 

 12.5 

 13.5 

 14.5 

 15.5 

 16.5 

 17.5 

 18.5 

 19.5 

 20.5 

 21.5 

 22.5 

 23.5 

 24.5 

 2.31 

 6.61 

 10.04 

 12.22 

 13.04 

 12.63 

 11.30 

 9.41 

 7.35 

 5.41 

 3.75 

 2.46 

 1.53 

 0.90 

 0.51 

 0.27 

 0.14 

 0.07 

 0.03 

 0.01 

 0.01 

 0.00 

 0.00 

 0.00 

 0.00 

 1.73 

 5.02 

 7.81 

 9.85 

 11.01 

 11.30 

 10.84 

 9.79 

 8.40 

 6.86 

 5.35 

 3.99 

 2.85 

 1.96 

 1.29 

 0.82 

 0.50 

 0.29 

 0.16 

 0.09 

 0.05 

 0.02 

 0.01 

 0.01 

 0.00 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

___ 

Vave @ 10 m Vave = 5.8 m/s @ 10 m Vave = 6.7 m/s @ 10 m Vave = _____ 

The following equation shall be used to compute the wind speed as a function of height 

above the ground. For the COE Reference Sites, the wind shear exponent α = 0.143. 

For the Design Site, the Subcontractor shall specify the wind shear exponent. 

V(z) = V10m (z/10m)α

Note that turbulence levels and extreme gust conditions used for design analyses are not 

described by the wind-speed probability distributions given above. These values shall be 

clearly defined by the Subcontractor and reported to NREL in appropriate deliverable 

reports. 
21

References 

1. Wind Turbine Generator Systems - Part 12: Power Performance Measurement 

Techniques. International Electrotechnical Commission (IEC), Technical Committee 

(TC) No. 88, Standard 1400-12, CDV Draft, February 8, 1994.
22

APPENDIX B 

ATTU Subcontractor Data Input Worksheet 

Figure B1a. ATTU subcontractor input worksheet (continued in Figure B1b).

Subcontract 

Technology Maturity 

Weight Entry 

A

Weighted 

TIO 

Impact 
23

Figure B1b. ATTU subcontractor input worksheet (continuation of Figure B1a). 

Subcontractor Work 

Progress Entry 
F1147-E(12/2004) 

REPORT DOCUMENTATION PAGE Form Approved 

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PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

1. REPORT DATE (DD-MM-YYYY)

June 2005 

2. REPORT TYPE

Technical Report 

3. DATES COVERED (From - To)

 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Low Wind Speed Technologies Annual Turbine Technology Update 

(ATTU) Process for Land-Based, Utility-Class Technologies 

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

NREL/TP-500-37505 

5e. TASK NUMBER

WER5.3200 

6. AUTHOR(S)

S. Schreck and A. Laxson 

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory 

1617 Cole Blvd. 

Golden, CO 80401-3393 

8. PERFORMING ORGANIZATION 

REPORT NUMBER

NREL/TP-500-37505 

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NREL 

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13. SUPPLEMENTARY NOTES

14. ABSTRACT (Maximum 200 Words)

The Low Wind Speed Technologies (LWST) Project comprises a diverse, balanced portfolio of industry-government 

partnerships structured to achieve ambitious cost of energy reductions. The LWST Project goal is: “By 2012, reduce 

the cost of energy (COE) for large wind systems in Class 4 winds (average wind speed of 5.8 m/s at 10 m height) to 

3 cents/kWh (in levelized 2002 dollars) for onshore systems.” The Annual Turbine Technology Update (ATTU) has 

been developed to quantify performance-based progress toward these goals, in response to OMB reporting 

requirements and to meet internal DOE program needs for advisory data. 

15. SUBJECT TERMS

low wind speed technologies; wind energy; cost of energy 

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