Solar-to-Grid: Trends in System Impacts, Reliability, and Market Value in the United States with Data Through 2019
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Solar-to-Grid: Trends in System Impacts, Reliability, and Market Value in the United States with Data Through 2019


With continued deployment of solar across the United States, assessing the interactions of solar with the power system is an increasingly important complement to studies tracking the cost and performance of solar plants. This project focuses on the historical contribution to reliability, trends in market value, and impacts on the bulk power system of solar deployed in the U.S. through the end of 2019. The scope of this analysis includes the seven organized U.S. wholesale power markets and is based on historical hourly solar generation profiles for each individual plant larger than 1 MW or county-level aggregate profiles for smaller solar. In addition, we present a limited set of results for ten utilities that are outside of the independent system operator (ISO)/regional transmission organization (RTO) markets. Highlights include: -Solar Generation: Solar deployment in the California Independent System Operator (CAISO), where solar generation was equivalent to 18.7% of annual load in 2019, far exceeds the level in other ISOs. The New England Independent System Operator (ISO-NE) has the second-highest penetration, with solar generation equivalent to 4.3% of annual load in 2019. All other ISOs have annual solar generation shares at or below 2%. -Reliability Contribution: Solar’s contribution to the overall resource adequacy of the power system is measured by its “capacity credit”. While calculation methods vary across ISO/RTOs, summer capacity credits for solar in 2019 range 45-76% of a system’s nameplate capacity. Capacity credits have remained largely stable over the past years except in CAISO where solar’s capacity credit steeply declined in 2018. -Market Value: The market value of solar, defined here as the sum of the energy and capacity values, primarily varies across regions and years because of variations in average energy prices and capacity market prices. The energy value, based on the hourly solar generation and real-time power prices at pricing nodes near each solar plant, is the largest component of the market value across ISOs. In 2019, the average energy value spanned from $24/MWh in CAISO to $60/MWh in ERCOT. The capacity value of solar is based on the capacity credit of solar and the capacity price. The capacity value in 2019 was highest in the Southwest Power Pool (SPP; $25/MWh), though capacity prices there are based on estimates of bilateral capacity transactions rather than transparent organized capacity market prices, and lowest in the Midcontinent Independent System Operator (MISO; below $1/MWh). -Market Value Decline: The market value of solar in CAISO declined between 2012 and 2019, both overall and relative to annual average energy and capacity prices. In 2012, solar’s market value in CAISO was 40% higher than the value of a flat block of power (representing the market value of a generator that operates at full nameplate capacity in all hours of the year). By 2019, however, solar’s value was 31% lower than a flat block of power’s value because of a solar-induced shift in the timing of high and low energy prices and a reduction in solar’s capacity credit. In contrast, the market values of solar in regions where solar penetrations were low did not decline relative to average prices. -Overall Competitiveness: As solar’s market value declined in CAISO, its cost—as measured by levelized power purchase agreement (PPA) prices—declined at a similar pace, thus maintaining solar’s overall competitiveness. Solar was more competitive in PJM and the non-ISO utilities where the market value in 2019 exceeded the levelized PPA price of contracts signed in 2019. Solar was more competitive in ERCOT in 2018, and the energy value of solar was significantly higher in 2019 than 2018, but data to report an average PPA price were insufficient in 2019. -System Impact: In CAISO, the net load has shifted to resemble the “duck curve,” with particularly low net load during spring days and high ramps as the sun sets in the evening. Similar patterns emerge in real-time prices, with lower prices during the day and higher prices in the early evening. Ancillary service requirements, particularly regulation reserves, have increased during the day, as have regulation prices. Negative real-time prices during low net load days in the spring suggest growing challenges with providing flexibility. However, broader shifts in the system—including growing participation of western utilities in the Western Energy Imbalance Market and variations in hydropower levels—appear to have mitigated some challenges in 2019 relative to 2017, even with greater solar deployment in 2019. Impacts to the net load shape from solar are similarly evident in a number of non-ISO utilities in the Western U.S., for example Arizona and Nevada. With much less solar deployment in the other ISOs, solar impacts on the bulk power system are much less obvious.

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