Only a few years ago, utilities were still kicking the tires on battery storage. Now, they want full control— from design to construction and everything in between.
Only a few years ago, electric utilities were still kicking the tires on the potential applications of energy storage. home battery power storage
Lithium-ion batteries had already emerged as the market leader with rapidly declining costs and myriad use cases. But utilities, charged with maintaining safety and reliability at the least cost, were slow getting out of the gate, as they often are with new technology.
Today, however, the dynamic has dramatically shifted. Utilities no longer want to rely on third-parties for design, engineering, procurement, construction, and maintenance work: they aim to own as much of the project lifecycle as possible. The goal, they say, is to improve efficiency, establish standards, and develop internal expertise. When a battery system fails, utilities require an immediate response, as opposed to hours or days when relying on a manufacturer or supplier, which likely isn’t located in its service territory.
Christopher Hilling embodies that transformation. His position with Bellevue, Washington-based Puget Sound Energy — distributed energy resource engineer — was created two-and-a-half years ago to build out the initial framework for the utility’s energy storage roadmap.
Puget Sound Energy began its push to own more of the battery storage lifecycle when its first project was underperforming. No one internally knew what was causing the problem because everything related to the project was owned by a vendor. The vendor went on to change names and ownership, which inhibited the utility’s pursuit of support resources.
“We are essentially at their mercy,” Hilling said.
Over the last year, Puget Sound Energy has made a “concerted effort” to reinitiate the battery system and develop its own playbook for deploying and managing energy storage assets. The battle now, Hilling said, it with time: Puget Sound Energy wants to deploy approximately 1,200 MW of standalone energy storage capacity, which includes supply-side storage and distributed energy resources, by 2030,
“We want to know that we can assess (battery storage assets) and keep them operational without dealing with multiple companies. Sometimes, they come and go. That’s a potential risk for us as a utility,” Hilling said.
Hilling is tasked with supporting the development of an internal playbook for deploying energy storage projects. Standardization is paramount to limit Puget Sound Energy’s need to pilot and test systems from a wide variety of manufacturers. Hilling wants to partner with vendors that can support as many use cases as possible with the fewest configurations.
Much of that work occurs through benchmarking with neighboring utilities and attending industry events, like DISTRIBUTECH International, Hilling added.
Dominion Energy is further along on a similar journey. Virginia’s Grid Transformation and Security Act of 2018, which required Dominion to pilot 30 MW of energy storage. Then in 2020, the Virginia Clean Economy Act upped the ante to 2,700 MW by 2035, which included applications for utility-scale resource adequacy, non-wires alternatives, and behind-the-meter resources.
“We needed to focus on developing these programs,” Ellen Jackson, Dominion’s program manager for distributed energy resources. “(Energy storage is) exciting, but there are still many unknowns.”
The problem was that no utility in the U.S. had developed best practices for energy storage due to the immaturity of the technology.
In its initial pilots, Dominion did not have the internal teams necessary to execute the projects on their own. They relied heavily on engineering, procurement, and construction firms. Dependency is uncomfortable for any utility.
“We learned a lot going through that process of what it looked like to build a stationary storage site and perform maintenance,” Jackson said. “We gained knowledge on what we have the skills to handle internally or could perform with additional skillsets brought in-house. We want to grow that knowledge.”
For a vertically integrated utility like Dominion, energy storage use cases are plentiful: grid services, resource adequacy, resilience, non-wires alternatives, mobile energy storage during emergency events, and so on. That flexibility can also create challenges for a team in pursuit of standardization.
Dominion is now working with EPRI to develop its energy storage playbook. It will include vetted vendors, integration frameworks, maintenance plans, and safety protocols.
“We definitely would like to expand our internal capacity, but we are still very much in the piloting and understanding phase,” Jackson said.
For the distribution piece of Dominion’s business, safety is paramount. The fire risks that face lithium-ion batteries are not taken lightly by the utility.
Dominion is in the process of developing an energy storage operations and maintenance team to expand its internal knowledge pool and respond quickly to incidents. Without that experience, Jackson said batteries can seem like a “black box,” and leave utilities overly reliant on third parties.
“Consultants or EPCs can only tell you so much. Their focus is on executing well. When you have internal teams doing some of this work, they understand from a long-term perspective,” Jackson added. “They’re in it for the long haul.”
Dominion is targeting non-lithium ion storage applications, too. The utility has partnered with long-duration energy storage provider Form Energy, which is developing an iron-air battery capable of discharging power for multiple days. They’re also testing a zinc-hybrid battery developed by Eos Energy, as well as a behind-the-meter metal-hydrogen battery from EnerVenue.
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Energy storage suppliers have noticed a shift in tone from utilities. But adoption and scale still face an uphill battle.
Part of the challenge is the rapid evolution of technology. A typical utility energy storage sales cycle can take 3 to 4 years from the signing of a deal to commercial operation, and storage technology often evolves at multiple points on that timeline. Another is lacking standards for integrating, operating, and servicing energy storage assets.
Just as the multitude of use cases for storage can lead to confusion for utilities, any scent of ambiguity can garner doubt from regulators, which require utilities to pursue least-cost solutions. That process gets muddy when a resource can be classified as generation and load, as well as a transmission or distribution asset.
“The business case is multifaceted and the regulatory framework is not,” John Zahurancik, president of Americas for battery manufacturer Fluence, said in an interview with POWERGRID International. “Eventually, we’ll figure that out.”
Fluence aims to support utilities on their path to standardization. The company wants its batteries to operate in the same way as any other asset in a utility’s fleet. That comes down to: 1) integration; 2) operation and physical management; and 3) safety, Zahurancik said.
While the sales pitch may be easier in some aspects for battery vendors, utilities are asking more thoughtful questions about safety, community engagement, cybersecurity, and long-term maintenance.
“We see the hunger,” Martin Rheault, the vice president of sales and business development for battery supplier EVLO Energy Storage, a subsidiary of Canadian utility Hydro-Québec, said. “The industry used to sell more standard solutions to utilities and independent power producers, and now they take more ownership in the process, from defining their own requirements to training their personnel for the long run.”
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