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Contract No. DE-AC36-08GO28308

Forecastability as a Design 

Criterion in Wind Resource 

Assessment

Preprint 

J. Zhang and B.-M. Hodge

National Renewable Energy Laboratory

To be presented at the 8th International Conference on Foundations 

of Computer-Aided Process Design 

Cle Elum, Washington

July 13–17, 2014

Conference Paper

NREL/CP-5D00-61398

April 2014 
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Forecastability as a Design Criterion in Wind 

Resource Assessment

Jie Zhang, Bri-Mathias Hodge*

National Renewable Energy Laboratory, Golden, CO 80401, USA

Email: bri.mathias.hodge@nrel.gov 

Abstract

This paper proposes a methodology to include the wind power forecasting ability, or 

“forecastability,” of a site as a design criterion in wind resource assessment and wind

power plant design stages. The Unrestricted Wind Farm Layout Optimization 

(UWFLO) methodology is adopted to maximize the capacity factor of a wind power

plant. The 1-hour-ahead persistence wind power forecasting method is used to 

characterize the forecastability of a potential wind power plant, thereby partially

quantifying the integration cost. A trade-off between the maximum capacity factor and 

the forecastability is investigated. 

Keywords: Wind power plant design, wind forecasting, forecastability, layout 

optimization, turbine selection, wind resource assessment, grid integration. 

1. Introduction

Wind power is gaining an increasing share of power production in the United States, 

producing 4% of U.S. electricity consumption as of August 2013 [1]. However, wind 

power is more variable and uncertain than power produced from traditional thermal 

power plants used to serve electricity demand. Load is also variable and uncertain, and 

at low levels of wind penetration the additional variability and uncertainty can be 

accommodated by the same mechanisms installed to accommodate load. As the amount 

of wind generation on the electric power system increases, new sources of flexibility 

will be required to help balance the variability and uncertainty at various timescales. 

Wind power forecasting is one such method that is used by utilities and independent 

system operators to reduce the uncertainty associated with wind power. At current 

levels of wind power penetration, wind can be effectively integrated wherever it may be 

installed; however, at higher penetration levels it might be more economically efficient 

to follow a design approach that chooses sites based on the correlation of their output to

load, or their ability to be forecasted. 

With the introduction of Federal Energy Regulatory Commission Order 764 [2], more 

of the responsibility for forecasting wind power plant output has shifted from the 

utilities and independent system operators to the wind power plant owner/operators. Not 

only do the operators have to provide meteorological information that can be used for 

forecasts, but they can also be assessed integration charges based on how well their 

forecasts match the actual wind power output. This makes a wind power plant site 

where the output can be well forecasted more valuable than a site where forecasting is 
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difficult—for example, perhaps because of complex terrain. This is especially important 

at the timescales that are most relevant to power system operations, namely those 

involved in the unit commitment and economic dispatch process. Day-ahead forecasts 

are typically used for unit commitment, and these forecasts are often based on numerical 

weather prediction models. Economic dispatch can utilize forecasts from 10 minutes up 

to 1 or 2 hours ahead. At these timescales, most models (weather physics-based or 

statistical) provide only slight improvements on the persistence method. Therefore, a 

measure of the 10-minute or 1-hour variability of a site corresponds well to its

forecasting ability, or “forecastability,” for the economic dispatch process. By 

examining the range of variability seen in a number of different wind power plant sites 

with a long time series of data, we can establish a measure of how well a potential site’s 

power output will be able to be forecasted, and hence what sorts of integration charges 

can be expected. These integration charges can vary considerably by location (for 

example, depending on what utility or balancing authority area the wind will be 

integrated into), but the charges are on the order of $1/MWh to $10/MWh [3] and thus 

could have a significant impact on siting decisions.

2. Methodology Development 

This paper develops a methodology to include forecastability in the stages of wind 

resource assessment and wind power plant design. The Unrestricted Wind Farm Layout 

Optimization (UWFLO) methodology is adopted here for wind farm layout 

optimization and turbine type selection. The wind power plant generation model in 

UWFLO is used to estimate the hourly power generation of the optimized wind power

plant. The 1-hour-ahead wind power forecasts are synthesized using a 1-hour-ahead 

persistence approach. 

2.1. UWFLO Methodology

The UWFLO methodology introduced by Chowdhury et al. [4, 5] avoids the 

assumptions presented by other methods that limit the layout pattern and the selection of 

turbines. In the UWFLO method, the turbine location coordinates are treated as 

continuous variables that allow all feasible arrangements of the turbines. The UWFLO 

method is applicable to both experimental-scale wind farms and full-scale commercial 

wind farms by: 

i. Using the wake growth model proposed by Frandsen et al. [6], 

ii. Implementing the wake superposition model developed by Katic et al. [7], 

iii. Including the joint distribution of the wind speed and direction, estimated by the 

newly developed Multivariate and Multimodal Wind Distribution model [8], 

iv. Modifying the power generation model to allow turbines with different hub 

heights and performance characteristics,

v. Evaluating the cost of the wind farm using an accurate response surface-based

wind farm cost model [9, 10], and

vi. Implementing a newly developed mixed-discrete particle swarm optimization 

algorithm [11]. 
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The objective of wind farm optimization here is to maximize the capacity factor (CF)

for a given wind site (wind speed and direction). The variables in the optimization 

problem are the locations of each turbine (Xj ,Yj ) and the type of turbine (T) to be 

used—a total of 2N + 1 design variables for a N-turbine farm. A turbine type is defined 

by a unique combination of rated-power, rotor-diameter, hub-height, and performance 

characteristics. In this study, we allow turbines to be selected from a pool of thirteen 2-

MW commercial turbines manufactured by Vestas and Gamesa. These turbine types are 

sorted in the order of their rotor diameters and their hub heights, and each turbine-type 

is then assigned an integer code between 1 and 13. The overall optimization problem is 

defined as

Max f(V) = Pfarm

NPr0

 Subject to 

g1(V) ≤ 0, g2(V) ≤ 0 (1)

V = {X1, X2, ⋯ , XN, Y1, Y2, ... , YN, T}

0 ≤ Xi ≤ Xfarm, 0 ≤ Yi ≤ Yfarm, T ∈ {1,2, ⋯ , Tmax}

where Pr0 is the rated power of the reference turbine (used for normalizing) and Pfarm is 

the power generated by the farm; and f(V) represents the capacity factor. The 

parameters Xi and Yi are the coordinates of the wind turbines on the farm. The 

parameters Xfarm and Yfarm represent the extent of the rectangular wind farm in the X 

and Y directions, respectively. The inequality constraint g1 represents the minimum 

clearance required between any two turbines. To ensure the placement of the wind 

turbines within the fixed-size wind farm, the Xi and Yi bounds are reformulated into an 

inequality constraint, g2 ≤ 0. The parameter Tmax represents the total number of 

commercial turbine types considered; Tmax = 13 for the case study considered in this 

paper.

2.2. Wind Power Forecasting

Wind power forecast models can be broadly divided into two categories [12]: (1) datadriven models, such as forecasting based on the analysis of recent time series of wind; 

and (2) first principle models, such as forecasting based on numerical weather 

prediction models. The first type of forecast models generally use statistical approaches 

to provide reasonable results in the estimation of long-term horizons, such as mean 

monthly, quarterly, and annual wind speed. The second type of forecast models 

generally use explanatory variables (mainly hourly mean wind speed and direction) 

derived from a meteorological model of the wind dynamics to predict wind power.

Economic dispatch can utilize forecasts from 10 minutes up to 1 or 2 hours ahead, and 

at these timescales most statistical models provide only modest improvements on the 

persistence method. Numerical weather prediction models are much better at producing 

accurate day-ahead forecasts, but they often perform much worse than persistence at 

small timescales. Therefore, a measure of the 1-hour variability of a site corresponds 

well to its forecastability for the economic dispatch process. In this paper, the 1-hourahead forecasts were synthesized using a 1-hour-ahead persistence approach. 
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The root mean square error (RMSE) between the 1-hour-ahead wind power forecasts 

and the actual power outputs is used to represent the forecastability of a wind site. In the 

study, the RMSE is normalized by the nameplate capacity of the wind power plant to 

obtain the NRMSE, which is between 0 and 1. A smaller RMSE or NRMSE indicates a 

higher accuracy of forecasts and a better forecastability of the wind site.

3. Data Summary 

In this paper, 5 potential wind power plant sites are evaluated and compared. Table 1

lists the locations, measured heights, and recorded years of these sites. Two sample 

wind rose diagrams at sites c and e are shown in Figure 1. 

Table 1. Locations of Analyzed Wind Power Plants

(a) Site d: NWTC M2 (b) Site e: Prison Draper

Figure 1. Wind rose diagrams at two potential sites

4. Results and Discussion

4.1. Optimal Wind Farm Layout and Turbine Selection

In this paper, 25 2-MW wind turbines comprise the fixed-size (land) rectangular wind 

farm that we consider. For all 5 wind power plant sites, 2-MW turbines with 90-m 

rotors were selected during the optimization. Different layouts were obtained at the 5 

sites, and two sample optimal layouts are shown in Figure 2. The capacity factors for 

the 5 sites are 0.23, 0.33, 0.40, 0.42 and 0.37. In this paper, project-specific power loss 

factors (turbine downtime for operations and maintenance, extreme weather conditions, 

snow accumulation, and curtailments) are not considered, leading to an overestimation 

of the capacity factor.

Station Latitude Longitude Measured Height (m) Year

(a) Butler Grade 45.9501 -118.6830 62.5 2010

(b) Cedar Creek 40.9541 -104.0780 80.0 2010

(c) Jewell 39.7842 -98.1192 80.0 2004

(d) NWTC M2 39.9107 -105.2350 80.0 2010

(e) Prison Draper 40.4889 -111.8900 50.0 2004
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(a) Site d: NWTC M2 (CF=0.42) (b) Site e: Prison Draper (CF=0.37)

Figure 2. Optimized wind power plant layouts

4.2. Wind Power Forecastability

The kernel density estimation [13, 14] is adopted in this paper to model the distribution 

of wind power forecast errors for different sites. Kernel density estimation is a 

nonparametric approach to estimate the probability density function of a random 

variable. Figure 3 shows the distribution of 1-hour-ahead wind power forecast errors at 

the 5 sites. It is important to note that the hour-ahead variability differs quite strongly 

among the sites.

Figure 3. Distribution of 1-hour-ahead wind power forecast errors

4.3. Trade-Off Between Maximum Capacity Factor and Forecastability

In this paper, the forecastability of a site is measured by the NRMSE of 1-hour-ahead 

wind power forecast errors. The trade-off between the maximum capacity factor and the 

forecastability is illustrated in Figure 4. It is observed that some potential wind power

plants sites (e.g., site d) have significantly larger capacity factors than others (e.g., site

a). However, the capacity factors are relatively similar for some sites, e.g., sites c and e. 

When the capacity factors of potential wind power plants are similar, it would be very 

important to consider the forecastability of each wind power plant because of the larger 

integration costs that might be assessed to the less forecastable of the plants. Among the 
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5 potential wind plant sites, site d is considered to be a more suitable wind plant site, 

with the largest capacity factor and the smallest NRMSE.

Figure 4. Trade-off between maximum capacity factor and forecastability

5. Conclusions

This paper investigated the effects of wind power forecasting on wind resource 

assessment and wind power plant design. To evaluate the forecastability of a potential 

wind power plant, the 1-hour-ahead wind power forecast errors were quantified and 

assessed. The UWFLO methodology was used to maximize the capacity factor of 

potential wind power plants. The trade-off between the maximum capacity factor and 

the wind power forecast errors indicates that the forecastability of the sites could make 

an economic difference for wind resource assessment and wind farm design, especially 

when the capacity factors of potential wind power plants are similar. 

Acknowledgment

This work was supported by the U.S. Department of Energy under Contract No. DEAC36-08-GO28308 with the National Renewable Energy Laboratory.

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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

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