Growing penetrations of distributed solar under net energy metering (NEM) have spurred debate, and in some cases, changes to how distributed solar will be compensated in the future. Perhaps just as importantly, these debates have highlighted the need for rate reform more generally. In an age when airline prices can motivate you to spend the night on a plane, and Uber has surge pricing, it seems antiquated to pay bundled, volumetric rates for electricity service.
Years of wind and solar integration studies conclude that an essential part of the integration solution is the participation of load in balancing the system and providing ancillary services. Bundled, volumetric rates don’t incentivize load participation. We also know that with increasing penetrations, solar declines in value faster than wind because solar output is concentrated into the daylight hours of the day. The main mitigation options for integrating solar are storage and load participation: we move the generation to match the load, or we move the load to match the generation. Storage costs are dropping quickly and will play an important role in integrating high penetrations of solar. However, storage is also a significant new infrastructure investment and storage is not a zero-carbon generation source but rather a net consumer of energy. From a ratepayer perspective, let’s make the most out of our existing infrastructure.
In a recent study for Colorado Springs Utilities, we examined the impacts of different rate designs on 1) solar and non-solar customer bills and 2) recovery of cost of service by the utility. This study calculated the value that distributed solar brought to their system and determined that for the residential and commercial solar customers, the utility did not recover their costs (net of the value of solar). While this shortfall is small today, it will increase as more distributed solar is added, and as the value of solar declines at higher penetrations. Because the utility must recover costs of service, there is a concern that costs are shifted from solar customers to non-solar customers. Increasing the fixed charge could be used to recover these cost shortfalls, but it wouldn’t incentivize efficiency nor would it help integrate higher levels of solar. Applying a value of solar tariff would help the utility recover costs by significantly raising the bills of solar customers, but this would disincentivize solar. Also Colorado statute requires NEM, so this would have to be an optional tariff, and not an attractive one at that. A better option is to moderately raise the bills of solar customers while simultaneously reducing their cost of service, such as through a time-of-use (TOU) rate. Time-varying rates can also help the utility integrate higher penetrations of solar. TOU rates can impact the system in a similar way to storage and in fact, we can calculate the value stream of benefits from time-of-use rates in a similar way to the value of storage. Using price elasticities from experience in Ontario, we found that energy and capacity value dominated the value stream, and that the total value stream from applying TOU rates to residential and commercial customers was comparable to the aggregated value from solar in our low penetration scenario.
California will be moving to default TOU rates in 2019 and we expect this should result in a host of enabling technologies (iPhone apps to manage your energy use, anyone?) available to consumers to manage their energy usage. The rise of third party aggregators is also likely to enable energy management for those consumers who don’t want to manage it themselves. The flexibility afforded by TOU rates can also influence what types of distributed energy resources (DERs) are installed and how they are used. Rooftop solar will be followed by electric vehicles, storage, and likely other DERs that we haven’t even envisioned yet.
TOU rates aren’t a silver bullet, but rather a first, baby step. Retail rates are set in advance and take time to change. Especially as hourly penetrations of wind and solar become a stronger driver of prices, it is going to be difficult to make a forecast now of when the actual peak, shoulder and off-peak times will be in 2019 or beyond. Day-ahead or real-time pricing would give load more accurate pricing signals to benefit system operations. But more dynamic pricing may require more utility infrastructure, more sophisticated energy management tools, and educational outreach for customers. And the slow pace of rate reform means we need to start working on this now. It’s clear that in a high wind and solar future, we will need to extract flexibility from load and that dynamic pricing will be a powerful and essential partner in that endeavor.
Reference: GE, “Solar Program Design Study”, July 24, 2017.
Debra Lew, Technical Director