Current Technology

Current Performance: Operational data for current technology is widely available from California windfarms and other locations around the world. Performance indicators for the base year are a composite of commercial technology available in 1996, including turbines from the DOE Near-Term Product Development Project [21-23] and from several othe r manufacturers [24]. These turbines include fixed and variable speed designs, most of which use one or more low cost, induction generators. The 1996 technology composite is distinguished from earlier technology, late 1980s/early 1990s, by the substantial use of power electronics for power conversion and/or dynamic braking, and by the use of advance d airfoil designs. Projects using these types of technology currently exist. Additionally, manufacturers have achieved high turbine availability with recent projects using these turbines or their direct predecessors [25].

As shown in Figure 3, the formulation of energy indicato rs for the 1996 base case and future years is based on the turbine size and subsystem characteristics for each time period. Specifically, a curve plotting the efficiency of power conversion from the wind through the rotor (which is known as the "coefficient of power" or Cp) was developed to be consistent with composite design characteristics of the turbines and includes the level of aerodynamic performance expected fro m improved wind turbine rotors for each time period. For example, the 1996 composite turbine was modeled as a fixe d speed, fixed pitch machin e. The rotor, generator, transmission and power electronics efficiencies were then incorporated directly into the Cp curves. For each time period, a curve of the net electrical power output, a "power curve," was then derived from the Cp curve. Finally, annual energy capture for each year was calculated using these power curves assuming a Rayleigh distribution for wind speed classes of 4 and 6 (5.8 m/s, and 6.7 m/s average windspeeds, respectively , measured at 10 meters above the ground). The sea level value for air density of 1.225 kg/cubic meter is used for all energy calculations. A wind shear expon ent of 1/7 is also assumed. A modeling tool developed for NREL was used to perform these calculations [26].

Technology Characteristics

Technology Characteristics


Figure 3. Methodology for estimating annual energy production .


Figure 3. Methodology for estimating annual energy production .

To ensure that projections are sufficiently conservative, the energy production model was used to calculate a measure of efficiency for each year's turbi ne, relative to its theoretical maximum. The right side of Figure 3 illustrates this process. To perform this calculation, the power coefficients corresponding to each po wer curve are set at their theoretical maximum (0.593, known as the Betz limit) from a cut-in windspeed of 2 m/s, up to their rated power at 11 m/s. From 11 m/s, up to 30 m/s, the power output is held constant at rated power, while the power coefficients are adjusted downward, i.e., the rotor does not convert all of the power that it theoretically can from the wind above 11 m/s because the generator would have to be larger than is economically optimum. Turbine efficiency, as listed in Table 1, is thus defined as the projected net energy produced by the TC turbine system, including all losses, divided by the energy generated from the theoretical best system, assuming no system losses. A more detailed discussion of this method may be found in reference 27.

Table 3 compares the 1996 wind TC energy indicator kWh per squar e meter of rotor area (kWh/m2) against the calculated performance of 17 recent turbines from 11 manufacturers, including the Bonus 600/41, Cannon/Wind Eagle 300, Enercon E-40, Flowind AWT-27, Kenetech 33M-VS, Micon M1500-750/175, and M1500-600/150, Nedwind NW41, and NW44, Tacke TW-600, Vestas V39/500, V39-600, V42/600 and V44/600, Wind World W3700/50, and Zond Z-40 and Z-46.

Publicly available power curves for these turbines are used to run the same energy model that was used to calculate the wind TC composite energy production estimates to produce comparable energy output estimates for class 4 and class 6 wind sites. For comparison, all turbines are normalized to the hub height of10 meters to eliminate the effect of different tower heights associated with the different commercial turbines.

Table 3. Comparison of current turbine performance with 1996 TC composite turbine.

Turbine Rating (kW)

Rotor Diameter (m)

Annual energy (kWh/m2 normalized to 10 m hub height, no losses, 100% availability) *

Class 4

Class 6

Minimum Value





Maximum Value





Mean Value





Stnd. Deviation





TC Value





*10 meters is height at which wind speeds are measured. Normalization eliminates effect of tower heights.

*10 meters is height at which wind speeds are measured. Normalization eliminates effect of tower heights.

Table 3 shows that the 1996 TC turbine rotor diameter and rating are similar to the mean values of the 17 turbines. The 1996 annual energy estimates for the TC turbine are one standard deviation above the mean values for the 17 turbines for both the class 4 and class 6 calculations. Since the turbines in this data set are optimized for various wind regimes, the result of this statistical analysis tends to overs tate the distance of the TC value from the mean. That is, the TC energy production would be closer to the mean of those turbines if they were all optimized for the TC wind resource assumptions. Thus, the composite performance estimate represents leading commercial techno logy, but is still under the maximum value for current machines. Individ ual turbines are not shown in the table because manufacturers were not given the chance to optimize their turbines for the TC wind resource assumptions. However, it is assumed that the large number of turbines included provides a reasonable range against which to b enchmark the TC composite estimate for current technology. The uncertainty range for 1996 energy indicators in Table 1 is within the bounds created by the minimum and maximum values listed in Table 1.

Windfarm Losses - A breakdown of assumed losses is shown in Table 4.

• Array Losses - Large downwind spacing dimensions (2.5 diameters sideways x 20 diameters downwind) have been assumed for class 4 sites because land is most often found in flat plains areas and is abundant for this resource class. Based on judgement of DOE laboratory researchers, this relatively large spacing is the primary reason for reduction of array losses from levels currently reported in some large, densely-sited windfarms in California. Array losses are assumed to be zero for the higher class 5 and 6 sites because these resources are often found in ridge or mountainous terrain and turbines are typically situated large distances downwind from one another or in long, single rows.

• Soiling losses - 1996 values are based on (1) tests of airfoil designs developed by NREL and availabl e commercially, that exhibit low sensitivity to soiling ("roughness") [28,29] and (2) the assumption that blade washing is conducted at economically optimal levels and the associated cost is included in the annual O&M. Introduction of variable pitch rotors in the 2000 TC design further reduces soiling losses; the pitch control is assumed to compensate for degradation of aerodynamic performance from soiling. Soiling losses decrease slightly after 2010, indicating that airfoil design and materials will not yet be fully optimized for roughness insensitivity until then.

Table 4. Windfarm loss assumptions (% of calculated

gross energy).







S / 0*

S / 0

4.S / 0

4.S / 0

4 / 0

Rotor Soiling





2 / 0

Collection Systemf






Control & Misc.







17.S /12.S

12.S / 7.S

11 / ó.S

11 / ó.S

10 / S.S

* Pairs indicate losses for wind (class 4 sites / classes 5 & 6 sites)

* Pairs indicate losses for wind (class 4 sites / classes 5 & 6 sites)

f Includes wire and transformer losses

Current Cost: Using public price quotes and engineering cost studies as the primary basis for the TC 1996 turbine FOB price estimate raises several issues. Foremost among these include:

• Differences may exist between advertised list prices, which are quoted by manufacturers for marketin g purposes, and actual market prices, which are project-specific, depending on what the market will bear.

• Price estimates derived from engineering stu dies are based on production cost plus an assumed profit, which may not match current market conditions. A major source of uncertainty in turbine capital cost estimates comes from trying to infer turbine and windfarm costs from quoted prices. That is, competitive pricin g strategies can make it difficult to determine true costs.

• Differences in, or lack of definition of, the volume of production associated with cost estimates and pric e quotes. This applies both to the cumulative volume, which determines how much cost reduction has been obtained through manufacturer "learning," and to the volume of the individual or annual production ru n associated with the cost, which affects the cost of purchased subcomponents, manufacturing materials, and distribution of fixed overhead costs. Normalizing estimates for these factors must often be attempted with imperfect information. Turbine costs in the TC for 1996 assume that the manufacturer has achieved a cumulative production volume of approximately 150 units prior to 1996 and that the size of the production run associated with the cost estimates is approximately 150 units.

• The differences between the U.S. market and other markets around the world, e.g. differences in subsidies, application size and type, ownersh ip/financing, and exchange rate fluctuations and that most recent projects have been installed in countri es other than the U.S., increase the difficulty of using recent market prices and quotes that are directed primarily at those markets.

• The difficulty in determining what costs are included in price quotes, e.g., substation costs or projec t management fees.

There is a large data set of current prices resulting from the substantial w orld-wide wind turbine industrial base. The 1996 TC cost composite draws from a combination of public information from manufacturers and published price quote s [25,30,31]. A statistical summary of this data from references 25 and 30 is shown in Table 5. Eleven turbines from eight manufacturers are included in this analysis. Assumptions concerning associa ted cumulative and annual production volume are not available from the data sources. European turbine list prices from [30] were reduced 15 percent due to the following reasons:

• Reference 30 is a document for general public information. Actual market prices will vary depending o n many project-specific factors.

• It is assumed that manufacturers quoted prices for their primary current market, Europe, which is supported by various market subsidy programs, especially in Germany. It is further assumed that subsidies tend t o support somewhat higher prices.

Total installed costs are calculated in Table 5 by increasing FOB cost by the 1996 wind TC value of $250/kW for BOS costs. Since the FOB cost was not available for the Zond Turbine, the installed project cost estimate was taken from a 1994 public briefing by the manufacturer and is assumed to be an estimate for general analytic purposes only [25]. The table shows that the 1996 wind TC composite cost estimate is close to the average value of this data set, after the 15% turbine price correction.

The 1996 TC cost does not include data points for two lightweight designs because they have not seen recent sales in the market. Nonetheless, costs associated with these designs appear to be significantly lower than those represented i n Table 5. Reference 30 gives a lis t price for the Carter CWT-300 at $666/kW. This turbine was developed several years ago. In addition, current experience with the production of six prototypes of the later free tilt, free yaw Cannon Win d Eagle 300 design indicates that the 1996 TC figure could easily be met or surpassed with current technology [32]. I n addition, a detailed engineering cost analysis performed under the DOE Near-Term Product Development Projec t estimated the on-site cost for 500 WC-86B turbines (the precursor to the AWT-27) including a 15% profit mark-up, to be $568/kW in 1992 dollars. Total project cost estimates depended on site-specific assumptions, but were approximately $800/kW [21].

Table 5. Comparison of current turbine costs with 1996 TC composite turbine estimate.

Turbine List Price ($/kW, Jan. 1997 $)

Total Installed Cost ($/kW, Jan. 1997 $)

Minimum Value



Maximum Value



Mean Value



Standard Deviation



Median Value



1996 TC Value



Number of Estimates



Mean Hub Height (m)



This characterization assumes, as a baseline for calculating fu ture cost reductions, that the nominal cumulative and annual production volume for 1996 technology is approximately 150 units. However, it is not possible to normalize the data in Table 5 for different cumulative or annual production volumes because it is not known what production volum e assumptions are behind the prices.

A low range of uncertainty in 1996 costs is shown on Table 1, reflecting extensive commercial experience to date. The larger uncertainty on the low side of the cost indicators, reflects the lower costs reported for emerging technology such as the Cannon/Wind Eagle 300. Estimates for emerging techn ology are not considered validated until a sufficient number of turbines have proven themselves in the field. In ad dition, market prices may be higher or lower than the stated bounds, depending on project-specific details such as access to transmission lines, and competitive circumstances.

Renewable Energy Eco Friendly

Renewable Energy Eco Friendly

Renewable energy is energy that is generated from sunlight, rain, tides, geothermal heat and wind. These sources are naturally and constantly replenished, which is why they are deemed as renewable.

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