Wind energy manufacturers and advocates must be enjoying the meltdown of solar power at the moment, as wind power has always been more competitive than solar with conventional fossil fuel electricity generation. Among other things, wind power doesn’t necessarily stop generating when the sun goes down.
However, the intermittency of wind power creates significant problems for grid operators that increase as the amount of installed wind power grows. The Department of Energy has noted this problem, writing last March on their website: “Often, wind generation does not coincide with the demand for electric power; wind resources are generally more prevalent overnight, when demand for electric power is at a minimum. In most areas, summer peak demand for electricity coincides with hot afternoons when consumers have turned up their air conditioners—but in many areas, such times are calm and wind resources may be quite low.”
The problem with any intermittent electricity source connected to the grid is that it requires a reliable backup source of power—usually natural gas these days—to ensure that the power reserves are adequate, especially for periods of peak demand such as summer heat waves, but also, as Texas found last winter, when unusually cold weather creates a spike in electricity demand. Last January, Texas experienced rolling blackouts because the grid was caught short. And wind production during that period was negligible.
The chart below from the Department of Energy, showing projections of the rated capacity of wind power by NERC (North American Electricity Reliability Corporation) region for the year 2019, cuts to the bottom line. While the installed capacity of wind power on paper—that is, assuming the wind is blowing at the right speed—looks impressive, in the real world grid operators can count on only about 8 to 13 percent of that capacity being available during peak times. (The table below shows the percentage of wind capacity available at peak times by NERC region). The Department of Energy’s headline for this release tells the story succinctly: “Electricity Resource Planners Credit Only a Fraction of Potential Wind Capacity.” This is one reason why the greenhouse gas emissions savings from wind power will diminish with the further spread of wind power.
Source: Energy Information Administration.
http://blog.american.com/2011/10/energy-fact-of-the-week-why-wind-p...
MAY 13, 2011
Industry projections of wind capacity by NERC region, 2019gigawatts (GW)
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0102030
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Source: U.S. Energy Information Administration, Form EIA-411,
Coordinated Bulk Electric Supply and Demand Program ReportNote: All projections were reported to EIA by electric power system planners during 2010, with a base year of 2009. Projections are reported for the time of summer peak demand. Capacities are given by NERC region (U.S. portion only; see
map). FRCC has no existing or planned wind capacity; wind capacity projected for SERC is very small.
Earlier editions of Today in Energy discussed the intermittent nature of wind generation (March 22, 2011) and the challenges it poses for electric power system operators (March 25, 2011) as the Nation's wind capacity rapidly increases. Today's story describes how electric power system planners treat wind generators, recognizing that the wind necessary to achieve a turbine's full generating capacity may not be available at the time of peak electric demand. In their long-range projections, planners count only a fraction of the nameplate capacity by "derating" a plant's capacity (i.e. applying a discount factor to it).
Electric power system planners forecast the demand for electricity at the time of the peak, and then identify existing and potential generating resources needed to satisfy that demand, plus enough additional resources to provide a comfortable reserve margin. The goal is to minimize the costs associated with new capacity investments while ensuring reliability for customers.
Capacity resource planners handle intermittent generation like wind differently from other generation1. Because of its unpredictable nature, planners reduce the amount wind contributes to the capacity needed to ensure reliability. Different planners answer the question "What is a reasonably conservative value to use?" in different ways.
The chart above displays electric power system planners' projections for wind capacity in 2019 (ten years out from EIA's most recent dataset) for the eight NERC regions (Florida's FRCC projected no wind capacity; wind capacity projected for SERC is very small). The light blue bars show how much of the total capacity the planners are willing to count on at the time of peak electric demand. The percentages reflect the assessment of the capacity value of wind at the time of peak electric demand (often late afternoon in the summertime). Peak capacity value is the wind available at the time of peak (light blue bar) divided by the total capacity (dark blue bar).
| NERC Region |
Wind Peak Capacity Value |
| ERCOT |
8.7% |
| MRO |
8.0% |
| NPCC |
13.2% |
| RFC |
16.6% |
| SERC |
9.9% |
| SPP |
8.2% |
| WECC |
18.5% |
The method for developing these peak capacity values2 varies by region. For instance, the Midwest ISO (mostly in MRO) uses a flat 8%; other planners use plant-by-plant operational data when available, and rely on engineering data for newly constructed or proposed wind plants. The data shown above are reported to EIA and NERC by electric power system planners. EIA's own projections use capacity values calculated using data on existing and projected generators and regional resource characteristics (for more information, see thedocumentation). EIA peak capacity values range from 15% to 30% across electricity market module regions (seemap).
Depending on how much wind capacity is in a region, a slight change in the rated capacity value for wind can mean a large change in future capacity requirements. Hypothetically, if a region projecting 20 GW of wind capacity by 2019 decreased its capacity value by one percentage-point from 12% to 11%, and had to replace that lost wind capacity in order to meet its target reserve margin, it would require an additional 200 MW of capacity resources by 2019. That 200 MW could come from a variety of traditional sources (gas, coal), or represent the available-on-peak portion of ~1800MW of additional wind. A conventional natural gas combustion turbine of the required size might require approximately $195 million in overnight capital costs (given the cost assumptionsused in EIA's Annual Energy Outlook).
1The capacity of wind, solar, and
run-of-river hydro capacity resources are consistently derated (reduced) for planning purposes. Some planners also derate demand response (which depends on consumer participation), and biomass.
2This peak-only capacity value is different than
capacity factor, which represents a plant's overall production relative to its maximum capability, regardless of time of day.
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