The price tag of a solar eclipse

The price tag of a solar eclipse

On August 21, 2017—for the first time in nearly four decades—a total solar eclipse is expected to traverse the continental United States. The last time we experienced an eclipse of this scope, renewable energy development was still gaining traction, and President Jimmy Carter was preparing to install the White House’s first solar panels.

The renewable market has changed considerably since President Carter set that example. The 2017 event marks the first time a total eclipse is occurring when solar resources command a big share of the electric generation portfolio in some portions of the U.S. Now that more parts of the country rely on centralized and distributed solar resources, more areas are also susceptible to system-wide impacts from sudden disruptions to solar production.

What does that mean for energy providers? Read on to find out.

What Will Happen to Solar Resources in Areas Affected by the Eclipse?

Huge swaths of the country will experience different degrees of solar “obscuration,” the percentage of the sun’s visible area that is blocked by the moon at a given location (typically expressed as a ratio between 0 and 1). This will cause a sudden drop and rise in solar power production within the span of a few minutes creating potential shockwaves in reliability and supply costs. In areas that rely on solar, such as California, system operators are expected to experience a sudden increase in net load that is typically supplied by centralized and distributed solar resources.

The eclipse is likely to cause a couple of challenges: system ramping and balancing concerns for areas and utilities with a high degree of existing solar penetration. Ramping is the action of starting or stopping generation on command. Each resource has a different ramp rate, so they would have to ramp up gas/hydro at a certain point before the eclipse as solar is ramping down, and vice-versa once the eclipse is over. This is all done to compensate for the reduction in solar generation during the eclipse. Providers will also have to deploy other resources to balance supply and demand during that time, since solar generation will be heavily reduced.

To address these concerns, system operators are likely to ramp up dispatch of fossil fuel-fired units to meet the fluctuations in system load on the day of the eclipse. While the North American Electric Reliability Council (NERC), a not-for-profit international regulatory authority, has determined that the solar eclipse is unlikely to cause any overall reliability issues to the North American bulk power grid, the temporary loss of the solar resource will have supply cost and other implications.

All Eyes on California

California will be at the heart of this nationwide experiment, with the highest installed solar capacity in the country at over 18 GW as of 2016. (The state with the second highest installed solar capacity is North Carolina with 3 GW.)  

California Independent System Operator (CAISO), which oversees one of the nation’s largest power grids, and NERC have each published reports on the implications of power fluctuation.

On the morning on August 21, 2017, CAISO estimates:

  • A large scale reduction of solar availability of around 5 GW.
  • A gross load increase of 1.6 GW, or 6-8% of the hourly load, due to unavailability of behind-the-meter solar resources.
  • An expected net load increase (i.e. load served by non-solar resources) of 6 GW.
  • A ramp rate increase from an average rate of 29 MW/min for CAISO to a high of 70-90 MW/min during the eclipse event.

The findings suggest the bulk power grid will handle the fluctuations smoothly, but these predictions raise another question: the price tag.

How Much Will the Eclipse Cost?

ICF developed a production cost simulation of the CAISO market using PROMOD, a wholesale electric market simulation model from ABB, for a base scenario without the eclipse event and an alternative scenario (assuming an average de-rate of 70% for solar resources) that takes into account expected reduction in solar output due to the eclipse event.

The model shows the expected decrease in the dispatch of solar units due to the eclipse, compensated by an increase in the dispatch of gas units. As a result, projected CAISO-wide average energy prices for August 21 increase by 1.3%, with the hourly zonal energy price for the morning hours increasing as high as 18.7%. A higher net load translates to an increase in California state ratepayer cost by approximately 7% for the day of August 21. For the three-hour block in the morning, the difference in ratepayer costs between the two scenarios is as high as 18%.   

What We Can Learn About Energy Use During the Eclipse—and How to Prepare for the Next One

The good news here is that the 2017 eclipse can tell us quite a bit about the hardiness of the North American bulk power grid. For the first time, we’ll be able to see the energy market response to system-wide fluctuations in solar power production. We’ll also learn more about system issues that will only become more relevant as solar becomes more widespread. But lessons from the solar eclipse aren’t just applicable to predictable astronomical events; they can also give us a sense of what to expect in the face of other threats to the grid, like extreme weather events or natural disasters.

And we should take advantage of this opportunity to test our systems on such a large scale. The next one won’t come for another seven years (April 8, 2024), when a total solar eclipse is projected to affect states between the Northeast and Texas. In the meantime, tell us what you think. How are you preparing for the eclipse? What do consumers need to know? What information should we be trying to collect during this one? Tell us on Facebook, Twitter, or LinkedIn.

Meet the authors
  1. Shankar Chandramowli, Director, Energy and Power Markets

    Shankar possesses over 10 years of experience in energy market consulting, with expertise in energy policy research, due diligence assessments, economic analysis of energy systems, and public stakeholder engagement.  View bio

  2. Himali Parmar, Vice President, Energy Advisory Services, Interconnection and Transmission

    Himali joined ICF in 2002 and is an expert in renewable integration, interconnection assessments, production cost modeling, forecasting transmission congestion and losses, and their effect on locational power prices and asset valuation. View bio

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