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With support from the U.S. Department of Energy Solar Energy Technologies Office, the National Renewable Energy Laboratory (NREL) partnered with Peak Reliability to evaluate the impact of the August 21, 2017, total solar eclipse on reliability and electric grid operations in the Western Electricity Coordinating Council (WECC) territory. As a North American Electric Reliability Corporation Reliability Coordinator, Peak Reliability manages the grid reliability across all or parts of the14 western United States, British Columbia, and the northern region of Baja California, Mexico. Peak Reliability used inputs from the study to augment its own analysis for preparing transmission operating plans for the day of the eclipse. Peak Reliability also provided NREL with data from across its footprint to uncover important insights into the impact of the eclipse from the penetration of photovoltaics (PV) along its path. The 2017 total solar eclipse came and went without causing any issues to the operation of the North American electric power system. This report presents the results of NREL's studies performed before and after the August 21 event. In a preevent analysis, NREL researchers focused on the spatial and temporal profile of the eclipse and how the output of PV sites across WECC would be affected. Although the size and location of utility-scale PV (UPV) sites are known and their outputs are monitored, distributed PV (DPV) (e.g., rooftop solar) poses a greater challenge for grid operations because of its lack of visibility. The estimated installed capacity of UPV and DPV across the WECC region is 15,800 MW (without concentrating solar power plants) and 9,200 MW, respectively. NREL used databases developed through previous efforts funded by the U.S. Department of Energy to determine how much DPV was present at the substation level and then estimated the impact of the eclipse on its output. This geospatial analysis assumes a typical meteorological day from NREL's typical meteorological year database. NREL researchers estimated that during the peak of the event, the loss of PV would be around 5.2 GW, with UPV loss at 4 GW and the rest from DPV. The second part of the analysis was a simulation of production costs. Using the results from the geospatial study, the economic dispatch and unit commitment strategies were evaluated to see how the other generators would be redispatched. The analysis showed that the loss of PV generation can be easily compensated by the existing generation fleet, with the natural gas fleet picking up the majority of the slack because of its flexibility. The change in system production costs were minimal. The third part of the analysis consisted of transient simulations to assess the stability and reliability of grid operations. No reliability concerns were identified, even for large system disturbance events. The system also exhibited high damping capabilities to mitigate inter-area oscillations.

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