Commentary
Grid edge

Late to the DER game, Sacramento tries a different strategy

The California city’s utility is trying to avoid the resource management challenges that have plagued the rest of the state.

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December 11, 2023
An aerial photo of homes in a town in the Sacramento Valley

Photo credit: George Rose / Getty Images

One of California’s smaller utilities wants to get ahead of the big problem of optimizing and dispatching distributed energy resources. 

The Sacramento Municipal Utility District is rolling out a slew of new technologies — including smart meters, two-way switches, fiber optic cables, and DER management software — to leverage the new resources being added to the grid.  

In October, SMUD received a $50 million grant from the Department of Energy’s Grid Resilience and Innovation Partnership program, which will fund the rollout of the new grid tech. 

The Wilton Rancheria Tribe of Miwok Indians tribal lands are the focal point of the project, dubbed Connected Clean PowerCity, and a portion of the grant will go directly to the tribe to install rooftop solar, storage, and heat pumps in homes and businesses. 

But the project’s impact will reach beyond tribal lands and into the rest of SMUD’s service territory. Rather than adding DERs in an unmanaged fashion, the utility wants to prepare for the coming influx by building a system that can immediately detect and manage new resources.

If successful, the technology selection and deployment strategy could serve as a blueprint for other utilities, both in California and elsewhere, that haven’t yet seen significant DER adoption. With so many offerings in the asset management market, SMUD’s approach could show what hardware and software are essential for DER management, and what is redundant or simply a nice-to-have. Compared to other utilities in the state, SMUD has low DER penetration. 

In 2022, the utility had nearly 45,000 rooftop PV systems installed in its service territory, versus a total of 1.7 million installations across the state, predominantly in the service territories of major investor-owned utilities. 

In my conversations with SMUD, the representatives for the utility said they hypothesize that its low DER adoption is a function of low electricity rates. Cheap electricity has the knock-on effect of lengthening the payback period on customer-owned assets. But the current lack of installations means the utility still has time to build out control and optimization capabilities, which means it could avoid some of the customer compensation challenges that have plagued the rest of the state. 

DERs are necessary for the utility to meet its goal of reaching net zero carbon emissions by 2030. To encourage more adoption, SMUD plans to build out distribution grid infrastructure that will support automated DER management. 

That means when customers install rooftop solar or purchase an electric vehicle, that asset can immediately be used for demand response or more dynamic load shifting like virtual power plants, and customers can be compensated accordingly. Most utilities are trying to play catch-up on automating DER dispatch for existing collections of resources at their disposal, but SMUD plans to use automation right off the bat.

As part of the Connected Clean PowerCity project, the utility will deploy 200,000 smart meters and 22,500 two-way switches to increase visibility and control of the distribution grid. The meters and sensors will be supported by 100 miles of fiber optic cable and a new DERMS. 

A look at the tech

After SMUD received an American Reinvestment and Recovery Act grant back in 2009, the utility installed Silver Springs Network’s AMI meters in its service territory. Now, those meters are reaching their end of lives, and will be replaced with new Itron meters. Unlike the first wave of AMI, which were primarily useful for transmitting data, the new meters are of a new generation. They’re embedded with chips capable of supporting distributed intelligence applications. In fact, SMUD prefers to refer to them as “sensors” instead of “meters.” 

One of the most critical advancements is an automatic connection between the meter and the transformer, which will allow the utility to monitor the transformer’s active temperature and voltage. Connecting all the meters on the same circuit would be a major step up for the utility in managing distribution side resources. 

The meters also have the capability to communicate their exact location. So when a homeowner purchases a new rooftop solar system, the utility will be able to pinpoint that new load, instead of approximating its location. This increases the overall visibility of the distribution grid.

The meters are one of two major hardware components of the project; the other is 22,500 two-way load control switches, which will allow SMUD to both control its DERs and automatically react to grid conditions, helping boost overall reliability.

Currently, SMUD offers a demand response program for customers with smart thermostats called Peak Conserve, which cycles air conditioners on and off during extremely hot days. The new switches will open that program to more people, because the utility can control the load shedding. Instead of sending a signal to a smart thermostat to reduce load, SMUD will send the signal to the switch itself. As DER penetration increases, the utility will be able to control more resources this way.

Meanwhile, 100 miles of new fiber optic cable will enable communication between grid-edge devices, and deliver data to the control center at five- and 15-minute intervals. The legacy networks currently supporting the distribution network cannot move data that quickly; in many areas, the fiber will be replacing much much lower latency 1G, 2G, and 3G networks.

On the software side, SMUD is working with Open Systems International to develop its DERMS in phases. The system is currently in phase one, transformer awareness, which is the voltage, temperature, and load monitoring enabled by the new meters. 

The next two phases will focus on more active management of the grid based on the state of transformers. For instance, if a transformer is approaching capacity, the utility could theoretically dispatch DERs to mitigate the work on the transformer. This type of control would make the grid more dynamic and reliable. 

SMUD’s initial goal is to install the new meters by 2026. All Rancheria homes and tribal-owned buildings will receive new meters, and the remaining meters will go to other customers. In total, the 200,000 meters will account for roughly 30% of SMUD’s service territory. The timeline for upgrading the rest of the meters is unclear. 

Crucially, for the next two phases, SMUD is still working out how to collect and organize data from different DERs to feed into the new DERMS. This will surely be a huge hurdle, and the utility said it is considering bringing in another technology partner to take this on. SMUD hopes to have phase three of the DERMS completed by 2026, which is a tight timeline given the unresolved data problems. 

While SMUD’s plans are promising, it will take at least two years before the utility can prove their strategy is capable of managing DERs upon arrival — until then, it will just have new meters and switches performing the same job as the old technology. 

 Assuming it works out, this approach could be genuinely transformative for other utilities with low DER penetration, and prove they aren’t too late to the game. But if it doesn’t, SMUD may find itself in the same boat as many other utilities: scrambling to leverage customer-owned clean resources that are essential for decarbonization.

Erin Hardick conducts research for Latitude Intelligence, the research organization connected to Latitude Media. She is also a producer for Latitude Media’s partner podcasts.

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