Wind Myths: Busted By Tom Gray

Power & Energy is the magazine of the Power Engineering Society (PES) of the Institute of Electrical and Electronics Engineers (IEEE), and in recent years, it has devoted one issue every two years to assembling many of the foremost experts in the field to examine the status of wind energy technology and its use by electric utilities.

The magazine’s editors have been kind enough to provide free access to two articles from the special issue here. Most significantly, one of the two is "Wind Power Myths Debunked," by Michael Milligan, Kevin Porter, Edgar DeMeo, Paul Denholm, Hannele Holttinen, Brendan Kirby, Nicholas Miller, Andrew Mills, Mark O’Malley, Matthew Schuerger, and Lennart Soder.

The Milligan et al article looks at a variety of mythic questions (e.g., "Doesn’t wind power need backup generation?") and addresses them in detail with appropriate graphics. I’m not going to go through them here, but I do want to call attention to the article’s conclusions, which I am going to list here in a modified, bulleted format for clarity:

– "Although wind is a variable resource, grid [utility system] operators have experience with managing variability that comes from handling the variability of load [customer electricity demand]. As a result, in many instances the power system is equipped to handle variability.

– "Wind power is not expensive to integrate …

– "…nor does it require dedicated backup generation or storage.

– "Developments in tools such as wind forecasting alo aid in integrating wind power.

– "Integration wind can be aided by enlarging balancing areas and moving to subhourly scheduling, which enable grid operators to access a deeper stack of generating resources and take advantage of the smoothing of wind output due to geographic diversity.

– "Continued improvements in new conventional-generation technologies and the emergence of demand response, smart grids, and new technologies such as plug-in hybrids will also help with wind integration."


"Wind Power Myths Debunked," by Michael Milligan, Kevin Porter, Edgar DeMeo, Paul Denholm, Hannele Holttinen, Brendan Kirby, Nicholas Miller, Andrew Mills, Mark O’Malley, Matthew Schuerger, and Lennart Soder

The natural variability of wind power makes it different from other generating technologies, which can give rise to questions about how wind power can be integrated into the grid successfully. This article aims to answer several important questions that can be raised with regard to wind power. Although wind is a variable resource, grid operators have experience with managing variability that comes from handling the variability of load. As a result, in many instances the power system is equipped to handle variability. Wind power is not expensive to integrate, nor does it require dedicated backup generation or storage.

Developments in tools such as wind forecasting also aid in integrating wind power. Integrating wind can be aided by enlarging balancing areas and moving to subhourly scheduling, which enable grid operators to access a deeper stack of generating resources and take advantage of the smoothing of wind output due to geographic diversity. Continued improvements in new conventional-generation technologies and the emergence of demand response, smart grids, and new technologies such as plug-in hybrids and electric vehicles will also help with wind integration.

THE RAPID GROWTH OF WIND POWER IN THE UNITED STATES AND worldwide has resulted in increasing media attention to—and public awareness of—wind generation technology. Several misunderstandings and myths have arisen due to the characteristics of wind generation, particularly because wind-energy generation only occurs when the wind is blowing. Wind power is therefore not dispatchable like conventional energy sources and delivers a variable level of power depending on the wind speed. Wind is primarily an energy resource and not a capacity resource. Its primary value is to offset fuel consumption and the resulting emissions, including carbon. Only a relatively small fraction of wind energy is typically delivered during peak and high-risk time periods; therefore, wind generators have limited capacity value.

This leads to concerns about the impacts of wind power on maintaining reliability and the balance between load and generation.

Can Grid Operators Deal with the Continually Changing Output of Wind Generation?

The power system—even before the development of windenergy technologies—was designed to handle significant variability in loads. Demand varies over timescales that range from seconds to years. System operational procedures are designed around this variability and, based on analysis and operational experience, much is known about how loads vary. Very short-term changes in load (seconds to minutes) are small relative to the system peak and consist primarily of many uncorrelated events that change demand in different directions. Over longer periods (several hours), changes in demand tend to be more correlated, such as during the morning load pickup or evening load falloff.

The output of a wind power plant, or multiple wind power plants, is variable over time. Because the variability of wind is added to this already variable system, there will be some incremental variability that must be managed by the system operator. Each megawatt generated by wind reduces the required generation of other units; therefore, the remaining nonwind generation units need only supply the load that is not supplied by wind.

This remaining load is often called the net load (load net of wind power). Therefore the nonwind portion of the power system is operated to the net load, which is the difference between load and wind. The difference between these traces is the wind generation.  At high penetration rates, it can be difficult to manage this incremental variability if existing generators do not have the required ramping capability. Generally, the (relative) variability of wind decreases as the generation of more wind power plants is combined.

Does Wind Have Capacity Credit?

The determination of whether there is sufficient installed capacity to meet loads allows for the possibility that some generation will not be able to provide capacity when needed at some future date. Generally, although the exact amount and procedures differ, system planners require a 12–15% margin of extra capacity as compared to peak load. This is known as the planning reserve margin.

The term “planning reserve” refers to the installed capacity of the generation fl eet and is separate and distinct from various types of operating reserves that are based on system conditions during operations. A more rigorous approach to evaluating planning reserves is to model hourly loads, generation capacity, and the forced outage rates of generators to determine the loss of load probability (LOLP) (i.e., the probability that generation will be inadequate to serve load). The LOLP can be used to determine the loss of load expectation (LOLE) that defi nes how many hours per year, days per year, or days in ten years that load might not be served. A typical LOLE target is one day in ten years.

Wind can contribute to planning reserves based on its influence on system LOLE—the same way that conventional units contribute to planning reserves. In most cases, wind makes a modest contribution to planning reserves, as indicated by capacity credit in the United States that ranges from approximately 5% to 40% of wind rated capacity. The wide range of capacity credit percentages assigned to wind reflects the differences in the timing of wind-energy delivery (when the wind blows) relative to system loads and periods of system risk. Once the capacity credit that may be assigned to a wind plant has been determined, it is the job of the system planner to determine the amount of additional capacity necessary to meet the system reliability criterion, regardless of the method used to procure the capacity.

How Often Does the Wind Stop Blowing Everywhere at the Same Time?

Individual wind turbine production is highly variable and grid operators are concerned that 100,000 MW of wind could present a severe reliability challenge. As explained above, wind benefi ts inherently from aggregation; therefore 100,000 MW of wind power does not behave like a single wind turbine. Aggregating wind over larger geographic areas decreases the number of hours of zero output. One wind power plant can have zero output for more than 1,000 hours during a year, whereas the output of aggregated wind power in a very large area always—or nearly always—is greater than zero. The variability also decreases as the timescale decreases. The second and minute variability of large-scale wind power generally is small; over several hours, however, there can be great variability, even for distributed wind power.

What about more significant weather events that can increase wind speed and require wind turbines to shut down for safety reasons and to protect the wind project? These events are not frequent. In some areas they do not occur every year, and in other areas they happen one to two times per year. Large storm fronts take four to six hours to pass over several hundred kilometers so, again, aggregating wind over a geographically wide area helps overcome this challenge.

For a single wind turbine, generation can decrease from full power to zero very rapidly. The aggregation of wind capacity, however, turns the sudden interruption of power into a multihour downward ramp. Texas experienced this type of wind event in February 2007.

Isn’t It Very Difficult to Predict Wind Power?

Wind-energy forecasting can be used to predict wind energy output in advance through a variety of methods based on numerical weather prediction models and statistical approaches. Wind forecasting is a recently developed tool as compared with load forecasting, and the level of accuracy is not as great for wind forecasting as for load forecasting. The experience to date suggests that the overall shape of wind production can be predicted most of the time, but signifi cant errors can occur in both the level and timing of wind production. Therefore, system operators will be interested in both the uncertainty around a particular forecast and the overall accuracy of the forecasts in general. Wind forecasts for shorter time horizons tend to be more accurate than forecasts over longer time horizons. For a single wind power plant, forecasts that are one to two hours ahead can achieve an accuracy level of approximately 5–7% mean absolute error (MAE) relative to installed wind capacity; this increases to 20% for dayahead forecasts.

Isn’t It Very Expensive to Integrate Wind?

The wind-integration cost is the additional cost of the design and operation of the nonwind part of the power system when wind power is added to the generation mix. Generally, at wind penetrations of up to 20% by energy, the incremental balancing costs caused by wind are 10% or less of the wholesale value of the wind power. The actual impact of adding wind generation in different balancing areas (or control areas) can vary depending on several factors, such as the size of the balancing area, the resource mix, and the extent to which the wind generation is spread out geographically.

The variability of wind power does not correlate with the variability of load. This means that the existing variability of the system can absorb some wind power variability. It also means that adding this new component of variability to a power system will not result in just adding up the total and extreme variability of both, because the extreme variations are not likely to coincide. Overall variability is determined by the square root of the sum of the squares of the individual variables (rather than the arithmetic sum). This means that reserves needed to balance variations in load net of wind are less than the sum of reserves needed to balance variations in the load alone or the wind alone.

The operational integration costs for wind will be less for larger balancing areas as compared with smaller balancing areas. Similarly, if the wind generation is spread over large areas, the per-unit variability decreases and the predictability of wind generation increases, leading to reduced wind-integration costs. Additional operating reserves may be needed, but that does not necessarily require new generating plants. The experience of countries and regions that already have quite a high wind penetration (from 5% to 20% of gross electric energy demand) has been that the existing reserves are deployed more often after wind power is added to the system, but no additional reserve capacity is required.

Doesn’t Wind Power Need New Transmission, and Won’t That Make Wind Expensive?

Historically in the United States, incorporating new generation sources has involved new transmission development. Federal hydropower facilities of the 1930s, 1940s, and 1950s included transmission facilities owned by the federal government. The development of large nuclear and coal plants in the 1960s and 1970s required interstate transmission facilities to deliver that energy. Similarly, transmission was constructed to access hydroelectric resources in Finland, Sweden, and Italy. Developing wind resources in the United States and internationally is also likely to involve developing new transmission. Transmission is required for meeting growth in electricity demand, to maintain electric reliability, and to access other generating resources besides wind generation needed to meet growing demand.

Several studies have found that, although the costs of building transmission to access wind resources are significant, consumers benefi t from reduced energy-production costs as a result of wind generation displacing other energy resources. The Joint Coordinated System Plan (JCSP), a conceptual transmission and generation plan for the Eastern Interconnection in the United States, indicates that a 20% wind scenario by 2024 would result in a benefit-to-cost ratio of 1.7 to 1. Additionally, transmission expenditures as a percentage of the overall costs of electricity to consumers are dwarfed by the costs of electricity production (e.g., fuel, operation, and maintenance) and the capital costs needed to develop the generation. For the JCSP study, incremental transmission costs comprise 2% of the projected total wholesale energy costs for 2024.

Doesn’t Wind Power Need Backup Generation? Isn’t More Fossil Fuel Burned with Wind Than Without, Due to Backup Requirements?

In a power system, it is necessary to maintain a continuous balance between production and consumption. System operators deploy controllable generation to follow the change in total demand, not the variation from a single generator or customer load. When wind is added to the system, the variability in the net load becomes the operating target for the system operator. It is not necessary and, indeed, it would be quite costly for grid operators to follow the variation in generation from a single generating plant or customer load.
“Backup” generating plants dedicated to wind plants—or to any other generation plant or load for that matter—are not required, and would actually be a poor and unnecessarily costly use of power-generation resources.

Regarding whether the addition of wind generation results in more combustion of fossil fuels, a wind-generated kilowatt hour displaces a kilowatt hour that would have been generated by another source—usually one that burns a fossil fuel. The wind-generated kilowatthour therefore avoids the fuel consumption and emissions associated with that fossil-fuel kilowatthour. The incremental reserves (spinning or nonspinning) required by wind’s variability and uncertainty, however, themselves consume fuel and release emissions, so the net savings are somewhat reduced. But what quantity of reserves is required? Numerous studies conducted to date—many of which have been summarized in previous wind-specifi c special issues of IEEE

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