The electric power industry has installed about 700 megawatts (MW) of utility-scale batteries on the U.S. electric grid, according to the Energy Department's Energy Information Administration.

As of October 2017, these batteries made up about 0.06 percent of U.S. utility-scale generating capacity. Another 22 MW of batteries were planned for the last two months of 2017, with 69 MW more planned for 2018.

EIA says that batteries, like other energy storage technologies, can serve as both energy suppliers and consumers at different times, creating an unusual combination of cost and revenue streams and making direct comparisons to other generation technologies challenging.

Market Drivers

Long considered the holy grail of electric power, energy storage increasingly is seen as a viable option for multiple utilities, including Caribbean island electric grids buffeted by hurricanes in 2017.

Credit: EIACredit: EIAA defining event for the storage sector can be traced to California and its response to the 2015 accident at the Aliso Canyon natural gas storage site. The accident shut the facility for months and threatened gas supplies to electric power generating facilities providing 10,000 megawatts of capacity to the region. Also at risk were dozens of industrial facilities and public buildings like schools and hospitals.

State regulators in May 2016 approved deployment of more than 100 MW of battery-based energy storage systems to help. Among the systems was the 20-MW/80 megawatt-hour (MWh) Mira Loma Battery Storage Facility, installed by Tesla in less than three months.

And at a utility substation in Escondido, a 30-MW, four-hour-duration lithium-ion Advancion battery array was installed by AES Energy Storage. At the time, it was one of the world’s largest such deployments.

The Aliso Canyon response showed that developers could design, build and commission significant amounts of energy storage in a short amount of time. Installing an equal amount of natural gas-fired generation likely would have required years rather than months.

Recent Announcements

Increasing numbers of utilities are announcing investments in energy storage technology for a variety of purposes.

Instead of rebuilding about 20 miles of transmission and distribution poles and wires, Arizona Public Service (APS) is installing two battery storage systems in a rural part of the state. The investment makes it one of the first electricity companies in the nation to use batteries in place of traditional infrastructure.

Arizona Public Service (APS) is installing two battery storage systems in a rural part of the state. Credit: APSArizona Public Service (APS) is installing two battery storage systems in a rural part of the state. Credit: APSThe two 4-megawatt-hour (MWh) Advancion batteries are made by AES Energy Storage. Construction on the project was set to begin in fall 2017.

Meanwhile, Florida Power & Light plans to add 30 megawatts of battery storage in parallel with more than 160 MW of solar generating capacity. The project is among the largest combined solar and storage facilities in the United States.

The utility provider says that renewable energy paired with what it says is a low-cost battery storage solution “provides a product that can be dispatched with enough certainty to meet customer needs for a firm generation resource.”

In May, Nevada lawmakers passed two bills aimed at establishing incentives for energy storage associated with solar systems, and directing state regulators to consider energy storage mandates. The commission has until Oct. 1 to make its decision.

In the Pacific Northwest, Portland General Electric Co. filed a plan Nov. 1 with the Oregon Public Utility Commission to develop up to 39 megawatts of energy storage.

The proposal calls for investing between $50 million and $100 million to deploy an array of energy storage projects to help integrate renewables into the grid, improve the region’s energy resilience and inform future investment in energy storage.

Meanwhile, in early December, Massachusetts awarded $20 million in grants to 26 projects to help develop the Commonwealth’s energy storage market. The projects will draw an additional $32 million in matching funds.

A study released in September 2016 said that 600 MW of energy storage technologies could be deployed on the Massachusetts grid by 2025. If deployed, the technologies could provide over $800 million in cost savings to ratepayers and reduce greenhouse gas emissions by 350,000 metric tons over 10 years.

And in a separate announcement, National Grid said in late November that it will install a 48 megawatt-hour battery energy storage system on Nantucket Island, 30 miles off the coast of Massachusetts, to help delay expected grid modernization investments.

Grid Modernization

But modernizing the grid is exactly the idea behind AES’s decision to donate a half-dozen 1-megawatt lithium-ion batteries to helping support Puerto Rico’s electric power grid, which was almost entirely destroyed by Hurricane Maria.

Credit: EIACredit: EIAAES is working with the Puerto Rico Electric Power Authority (PREPA) to site and deploy the batteries. According to Chris Shelton, chief technology officer of the Virginia-based company, the batteries — which AES is donating — will most likely support the still-fragile grid by enhancing both power quality and grid stability.

AES also sent Puerto Rican energy regulators a plan to modernize portions of the island’s grid using energy storage, mini-grids and expanded use of renewable energy, especially solar.

Xcel Energy CEO Benjamin Fowke told analysts on a late October earnings conference call that the utility, whose footprint stretches from northern Michigan to southeastern New Mexico, plans to make sure that storage “becomes increasingly more of a mainstream part” of its portfolio.

“I never short-change what technology can do," he said.

Cost Considerations

The decision to build a new power plant depends in part on its initial construction costs and ongoing operating costs. Although battery projects have a relatively low average construction cost, they are not stand-alone generation sources and must buy electricity supplied by other generators to charge and cover the round-trip efficiency losses experienced during cycles of charging and discharging.

EIA says that battery costs also depend on technical characteristics such as generating capability, which for energy storage systems can be described in two ways:

  • Power capacity or rating -- measured in megawatts, this is the maximum instantaneous amount of power that can be produced on a continuous basis and is the usual type of generator capacity discussed
  • Energy capacity -- measured in megawatthours (MWh), this is the total amount of energy that can be stored or discharged by the battery.

A battery’s duration is the ratio of its energy capacity to its power capacity. For instance, EIA says that a battery with a 2 MWh energy capacity and 1 MW power capacity can produce at its maximum power capacity for two hours. Actual operation of batteries can vary widely from these specifications. Batteries discharged at lower-than-maximum rates will yield longer duration times and possibly more energy capacity.

Short-duration batteries are designed to provide power for a short time, usually on the order of minutes to an hour, and are generally less expensive per megawatt to build. Long-duration batteries can provide power for several hours and are more expensive per megawatt.

On the revenue side, batteries have relatively low capacity factors because of charging durations and cycling limitations for optimal performance. Nevertheless, they can capture a range of value streams, which can sometimes be combined to improve project economics.

EIA says that some of the uses for batteries include:

  • Balancing grid supply and demand. Batteries can help balance electricity supply and demand on multiple time scales (by the second, minute, or hour). Fast-ramping batteries are particularly well suited to provide ancillary grid services such as frequency regulation, which helps maintain the grid’s electric frequency on a second-to-second basis.
  • Peak shaving and price arbitrage opportunities. By buying power and charging during lower-price (or negative-price) periods and selling power and discharging during higher-price periods, batteries can flatten daily load or net load shapes. Shifting portions of electricity demand from peak hours to other times of day also reduces the amount of higher-cost, seldom-used generation capacity needed to be online, which can result in overall lower wholesale electricity prices.
  • Storing and smoothing renewable generation. Storing excess solar and wind-generated electricity and supplying it back to the grid or to local loads when needed can reduce renewable curtailments, negative wholesale power prices coincident with wind and solar over-generation, and price spikes related to evening peak ramping needs. Co-locating batteries with solar and wind generators allows system owners to more predictably manage the power supplied to the grid by combined renewable-generator-and-battery systems.
  • Deferring large infrastructure investments. Local pockets of growing electricity demand sometimes require electric utilities to build expensive new grid infrastructure such as upgraded substations or additional distribution lines to handle the higher demand, which can cost upwards of tens of millions of dollars. Installing batteries at strategic locations, at a much lower cost, enables utilities to manage growing demand while deferring large grid investments.
  • Reducing end-use consumer demand charges. Large power consumers such as commercial and industrial facilities can reduce their electricity demand charges, which are generally based on the facilities’ highest observed rates of electricity consumption during peak periods, by using on-site energy storage during peak demand times.
  • Back-up power. Batteries can provide back-up power to households, businesses and distribution grids during outages or to support electric reliability. As part of an advanced microgrid setup, batteries can help keep power flowing when the microgrid is islanded, or temporarily electrically separated, from the rest of the grid.