Energy storage technologies continue to be viewed as a critical component to achieving various grid objectives, whether it is to reduce wasted energy, decrease the need for curtailment of generating assets, increase resilience, lessen transmission congestion, or facilitate increased use of solar and wind generation.
As part of a cooperative agreement with the Department of Energy, the American Public Power Association convened a group of public power professionals to discuss how utilities can remove barriers and increase adoption of energy storage solutions. A report from the first year of this effort, Integrating Energy Storage Solutions for Fossil Generation, outlines some of the current challenges public power utilities face in implementing energy storage technologies and offers strategies for implementing it. Members of the working group that contributed to the report provided deeper insight into how their utilities are thinking about storage and incorporating it into their operations.
The Pascoag Utility District in Rhode Island has a shared savings arrangement with a renewable energy company on a 3-megawatt, 9-megawatt-hour battery storage system that came online in July 2022. Michael Kirkwood, Pascoag’s general manager and CEO, said the system helps the public power utility to avoid regional transmission and capacity costs related to peak load.
Kirkwood said that the solar developer, Agilitas Energy, incurred the upfront capital costs, and the nature of the agreement incentivizes savings for both parties. Kirkwood explained how the system immediately began helping Pascoag save as part of its participation in ISO New England, which levies a transmission charge to participants based on their contribution to the monthly peak load and capacity charges on annual peak load. “They only get paid from us if they help us reduce our costs with ISO-NE. So, they have a direct interest in trying to reduce the peak load for both the transmission and capacity markets,” he said.
The market structure also incentivizes storage. “It does get competitive out there, so you want to be in a system that is reducing load during those critical times,” he said. “You wouldn’t want to be the last guy in, because as we reduce our peak, those left are picking up a bigger and bigger share.”
Even though the project was the first of its kind for Pascoag, Kirkwood typified the installation of the system as “pretty routine” and “fairly easy.” He said that the system went through a rigorous interconnection study with Rhode Island Energy to ensure it met all standards, and then Pascoag employees helped with the interconnection. The key work, said Kirkwood, comes in setting up the right automation parameters so that the system knows when it should be charging and when it needs to be ready to dispatch.
Once the system is up, he said, monitoring only requires a computer to check in on its performance and status — which can be a learning process in itself. The system is part of the ISO-NE regulation market, and receives dispatch signals from the ISO. Kirkwood said that means the system “swings on and off all the time” as a result. While not disruptive to Pascoag’s system, such swings, which can be 3 MW in a matter of seconds, represent a significant share of the utility system needs, which has a peak at 13 MW.
Although a third party manages the system for Pascoag, Kirkwood believes that operating such a system directly wouldn’t require too much additional effort since the system is unmanned and self-sufficient once up and running. He estimated that using a battery system for peak reduction, as Pascoag does, would require someone to check on the daily load forecast and maybe spend an hour ensuring the system is set up to be ready to dispatch during the peak hours.
Kirkwood said the utility does not have any plans to add more storage at this time but would be open to another project, either a standalone battery system or one paired with a solar facility.
Scott Harding, assistant director of utility operations for the City of Colton Public Works and Utilities in California, said that the utility is looking into the potential of deploying lithium-ion battery systems in weak spots throughout its system to bolster its ability to switch. Previously, the utility worked with several industrial customers to deploy Ice Bear systems, which are attached to the customers’ air conditioning units to help shift energy usage.
He stressed that utilities can get vastly different benefits from storage systems, depending on how they use them. Understanding Energy Storage, a 2018 report from APPA, outlines nearly a dozen potential services that storage technologies can provide, from black start to frequency regulation and energy arbitrage.
“If you’re letting it sit there, it’s just a reliability resource. If you are using it, [you] could possibly displace some of your natural gas facilities or help to integrate renewable resources.”
Still, he said, every utility will have different needs, and there is no “cookie cutter” approach for deploying storage within a system. Harding previously worked for a much larger utility system where he helped stand up a 30-MW storage project. There, he said, the focus was on how much energy use the battery could muster. At smaller utilities like in Colton, he sees storage getting the most economic value in providing ancillary services and as a reliability resource.
He said the biggest change for utilities in taking on storage is about making sure that employees understand where the value of the asset is coming from and how it can be used accordingly. “When people don’t understand how it works, it doesn’t get utilized in the most efficient manner.”
Harding said this is more of a concern in larger utilities, where different departments within the utility might have different uses for the asset, and not be aware of how one use would limit or prevent other uses. For example, if a reliability team expects to have a storage system available as a backup, then a finance team would not be able to use it for energy arbitrage.
He said that this type of issue can stem from changes that occur throughout the life cycle of the project development, which can shift from an initial economic analysis through the facility design. To prevent this type of issue from arising, Harding recommends that utilities ensure that “key people that understand how the technology works stick with the project from cradle to grave.”
Learning the Ropes
In North Carolina, the Greenville Utilities Commission began exploring storage as an option for reducing its peak demand. Kyle Brown, electric planning engineer with GUC, said that the utility has relied on diesel and natural gas to help with peak shaving for several decades, and it started looking into storage as battery technology began to advance.
“We’re very aggressive in the way we run our load management program, because the demand charge for that one hour is 50% of our wholesale cost,” said Brown. “We’re always looking for innovative technology or different solutions to help with our load management program, whether it’s smart thermostats, AMI, or anything like that. So, batteries were another thing that we wanted to explore.”
GUC piloted a 1-MW, 2-MWh battery storage system that is connected to one of its distribution substations. The cost of the 1-MW system was on par with what GUC saw for natural gas generators at the time. The system began operating in January 2021, and Brown said it immediately became part of GUC’s fleet of load management tools. While the current system is delivering value, Brown expressed doubts about using the current technology at a greater scale.
“The challenge for us all along has been that with a battery system, you have a finite capacity,” he said. “We don't know if the two-hour system is sufficient. … Our typical load management runs are about four hours. We haven’t had any issues in hitting the peak with our system, but if we were to start transitioning more of our fleet over to that limited capacity system, that would change the calculation a bit, and there would be a lot more risk.”
Brown said that GUC had explored the potential of adding a larger battery system, but the cost at the time was significantly higher and didn’t make financial sense. He stressed that given GUC’s structure and wholesale power agreements, the only service of value that storage can provide the utility comes through peak shaving, as it doesn’t have any concerns about generation, transmission capacity, or system reliability. He said that GUC is not looking to add any additional storage at this point, but that industrial customers could be interested in installing behind-the-meter systems to reduce their demand charges or for other purposes. Through the pilot, GUC has gained a better understanding of the technical aspects of battery technology to be able to advise customers on the systems when and if they choose to deploy them.
Another challenge, noted Brown, is in defining the project needs and in being as specific as possible about what the system will need to do. “On the engineering side, we didn’t have any previous history with batteries. Developing the specifications was one of those ‘We don’t know what we don’t know’ situations. There was a lot of effort that went into reviewing the literature and coming up with a specification that got the solution we needed from the operation standpoint.” He shared how he has heard from colleagues at other utilities who didn’t get the system they thought they were buying because the specifications were written in a way that could be misinterpreted.
GUC currently has a third-party agreement for system maintenance, and Brown said that is a function he would like to eventually move in-house. To get a sense of the skills needed to perform a lot of the routine maintenance, GUC ensures an employee is on-site when the contractor comes out to work on the system. This shadowing has helped the utility get a sense of the scope and complexity of attending to the system’s needs.
While public power systems seem to be getting benefits from today’s storage options, utilities note the technology still needs to develop to support a transformed energy system.
Despite having technologies that have been around for a while, Harding believes utility-scale energy storage is still in its infancy. In addition to continuing to see the economics of storage improve, he would also like to see developers focus on the flexible capacity value, rather than high amounts of energy offtake, of the assets and how they can be better paired with solar facilities. He also said that he would like to see storage technology or configurations that allow for facilities to take up a smaller footprint and improve safety. “This is a technology that is going to keep improving.”
Pascoag’s Kirkwood pointed to a need for long -duration storage that can easily ramp up and down as traditional fossil fuel-powered plants close. “One issue with the current storage environment is that they are fairly short. In the future, you are going to need resources that will carry you for a day or several days,” he said. While utilities could string together batteries or different assets to pull from throughout the day, such an arrangement would not be cost- effective nor practical. “It’s got to be cost-effective. … People are aware of the need, but the technology hasn’t caught up yet.”
GUC’s Brown agreed. “I don’t know that the current technology is necessarily the silver bullet. Until there’s a significant increase in storage capacity, it is kind of standing in the way of large-scale adoption.”