Energy storage spans the oldest and most elemental energy theory — such as flywheels — and some of the newest technology and emerging possibilities — such as hydrogen.
The expanding options in storage technologies, plus declining costs, hint that storage is poised to become a common asset for utilities across the U.S. Public power utilities that have deployed storage projects shared the reasoning for using storage and their plans for using it into the future.
A long history, a booming future
Pumped storage hydroelectricity dates back about a century in this country, to when a Connecticut utility began pumping water up to a nearby reservoir and gaining power as it needed from its flow downstream. Pumped hydro remains the most widely used storage technology because of the availability of water sources and the relative simplicity and low cost of the technology. Of the remaining storage, most is equally divided between battery and thermal storage, with a small percentage in compressed air and flywheel systems.
The various systems in use today include small units that freeze water during off-peak periods then use it to cool hot buildings, and lithium batteries connected to solar plants that can store hundreds or thousands of megawatts and power a small city when solar output drops.
While pumped hydro still dominates the storage landscape today (about 94% of the 24 gigawatts of energy storage capacity in the U.S.), the past few years have seen a boom in battery storage projects. According to the Energy Information Administration, the total installed capacity of large-scale battery storage was about 1 GW at the end of 2019, and developers plan to add more than 10 GW in battery storage from 2021 to 2023. Looking further ahead, EIA’s 2021 Annual Energy Outlook projects reaching nearly 60 GW, or 235 gigawatt-hours, of battery capacity by 2050.
The variability of renewables and demand for more reliable power, along with declining prices for the technology, have driven interest in storage in the last 10 years, according to Haresh Kamath, director of distributed energy resources and energy storage at the Electric Power Research Institute in Palo Alto, California.
There are a variety of reasons that the need for storage is becoming clear. For example, remote areas that relied on vulnerable transmission connections and, perhaps, diesel generators for emergencies are now more often relying on solar power but need the backup that can come with battery storage, Kamath said. Meanwhile, it may allow utilities to forgo adding new costly and carbon-emitting generation.
“For large systems, pumped hydro is hard to beat, but for smaller scale, lithium-ion batteries are gaining popularity and likely to be the biggest part of the storage put in place in the next 10 years. We are gaining a lot of experience with it and knowledge about it,” Kamath said.
In public power, exploration of newer storage options is happening in every region and at utilities big and small. As of August 2021, the Public Power Energy Storage Tracker lists 74 projects that are already online, ranging from batteries with a few kilowatts to pumped hydro with thousands of megawatt-hours in energy capacity.
The New York Power Authority is partnering with EPRI to evaluate a crushed rock thermal energy system. The project, which involves heating tons of crushed stone then producing steam for energy generation or hot water applications, is being funded with a $200,000 federal grant. Various other thermal storage systems are being explored, including some that use salt or concrete to store heat or use chemical reactions.
Benefits from projects big and small
At the Moreno Valley Electric Utility, which serves more than 7,000 customers in a bustling region east of Los Angeles, several smaller-scale projects are planned or underway, according to Jeannette Olko, electric utility division manager.
MVEU’s office is right across the street from city hall, where a solar carport is tied directly to the utility’s grid while some energy is stored in a 75-kilowatt lithium-ion battery that feeds two electric vehicle charging stations and discharges when the charging stations are in use.
The public power utility also worked with Ice Energy (now Thule Energy) to provide commercial customers with systems that would freeze water during nonpeak periods and use it to cool buildings when daytime temperatures rise. A utility field office is now evaluating the feasibility of a project to test similar units for area homeowners.
“Here in California, we see battery storage serving as an integral component for the reliable operation of the electric grid,” Olko said. “It is increasingly important to help with power supply issues, not to mention the potential operational benefits both at the state level and for our local distribution grid.”
She noted that it is particularly important with the growing amount of solar generation that her utility and its customers are bringing online. Approximately 20% of Moreno Valley customers have installed solar systems, totaling about 11 MW. Numerous factors have also driven a rise in behind-the-meter storage within the state, which accounted for 83% of all small-scale capacity in 2019.
“That high penetration of solar and the state’s efforts to give customers more control over their energy usage are driving the move to time-of-use rates,” Olko said. “Battery storage becomes a viable option for customers, especially those with solar systems, during the peak period hours of 4 to 9 p.m.”
On a bigger scale, Salt River Project plans in two years to bring online three new batteries with a combined capacity of 373 MW to serve some of the utility’s 1 million customers in central Arizona. Its Sonoran Energy Center will include a 260-MW, 1,040-MWh battery project, the largest in Arizona, while its Storey Energy Center solar and energy storage system will have 88 MW of solar and 264 MWh of energy storage capacity. Both the Sonoran and Storey energy centers are set to come online by June 2023 and will be owned and operated by subsidiaries of NextEra Energy Resources. These projects will put SRP in the mix of utilities with the largest amount of storage capacity in the country.
SRP already has three smaller battery systems (10–25 MW) operating or in the works and has operated several pumped hydro facilities since the 1970s.
Reaping the benefits
“Absent any breakthrough in technology, batteries are critical to the further integration of solar and wind,” said Chris Janick, senior director for power delivery at SRP. “Utilities like Salt River Project have ambitious goals for renewable power, and we view storage as essential to meeting them.”
SRP intends to add 2,025 MW of solar power by 2025 as part of sustainability goals intended to reduce carbon emissions by 62% in 15 years. And Janick noted that solar becomes much more valuable and flexible with the addition of efficient storage capability.
In Moreno Valley, Olko said storage can help solve what has become known as the duck curve — the swing in demand for electricity, which dips during the day when solar power is abundant and then ramps up quickly at night as solar generation ebbs.
“We have our own duckling curve on our system, and we want to find ways to avoid it having a dramatic effect on our customers,” said Olko.
She and others at the utility want to prepare by having the capacity to store energy and giving customers options to do so. The system peak for MVEU in 2020 was just over 53 MW.
Declining costs, increasing value
A string of factors can affect the cost of energy storage and its value to the utility, from its size and duration to its location and the purpose for it being discharged.
A 2019 report from the National Renewable Energy Laboratory noted that battery costs have been difficult to determine because the costs and technology have changed rapidly and there is limited history with the technology. However, the NREL report estimated that a 100-MW, 10-hour battery system would cost from $356/kWh to $399/kWh, with the direct current storage block accounting for about 40% of the total installed costs. In comparison, the report estimated project costs for pumped hydro to be $262/kWh for a 100-MW, 10-hour installed system, with the biggest costs coming from the reservoir ($76/kWh) and powerhouse ($742/kW).
In July, Secretary of Energy Jennifer Granholm outlined an initiative to reduce the cost of grid-scale, long-duration energy storage by 90% by 2030. She also described a $1.5 million package of support for the American Public Power Association to help public power utilities explore and deploy storage and other technologies to “make the grid cleaner and more resilient and more reliable and affordable.”
Even prior to the Biden administration signaling support for energy storage, experts forecast continued sharp declines in storage costs. In a 2020 analysis, The Brattle Group predicted that costs could decline from under $400/kWh in 2020 to below $200/kWh by 2040. It also found a 1.6 to 2.4 benefits-to-cost ratio, depending upon if just capacity and day-ahead energy value streams or others were included.
Savings vary according to the size and duration of the storage units and the ability to “value stack” the battery and efficiently use the storage for multiple purposes.
According to Laura Meilander, vice president of business development for Convergent Energy + Power, which develops utility-scale storage systems, utilities can save from 30% to 45% on transmission costs with appropriate storage.
“If peak shaving is combined with other revenue streams, we’ve seen energy storage provide worthwhile savings even at public power utilities with demand charges as low as $8/kW per month,” she said. “In areas where there are no other revenue streams available, we’re seeing energy storage make sense at $10-$12/kW-month demand charges.”
Battery storage systems typically require less maintenance than other utility assets, but Meilander noted utilities must decide whether to own or contract for them. Ownership, she noted, requires trained personnel who can operate and maintain the system and dispatch it to meet peak needs. SRP is contracting for its two biggest new units in part for those reasons.
Olko said that Moreno Valley is also looking at a utility-scale battery project, analyzing the best location for the project and the optimal size for its needs. Currently, she said, the project plans involve a 6.8-MW system discharging over four hours during peak, which could potentially defer installation of a third bank at one substation.
The utility is surveying its customers to find out their knowledge and attitudes about renewables and storage and to determine plans for adding any equipment.
EPRI’s Kamath noted that while many utilities are beginning to understand the different storage options, utility leaders should consider getting some experience with technology soon. “Stakeholders are going to demand it, and it will become increasingly important,” he said. “Having to deploy a lot of this in short order will be daunting.”
