Electricity resource planners credit only a fraction of potential wind capacity

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).

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 the documentation). EIA peak capacity values range from 15% to 30% across electricity market module regions (see map).

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 assumptions used in EIA's Annual Energy Outlook).