Where is the U.S. energy storage market going?
Storage deployments could triple this year and open big new markets
The 40% growth in yearly additions to U.S. energy storage capacity from 2013 to 2014 was big news but growth for 2015 is expected to more than triple to 220 MW.
The numbers explain why over half the utility executives queried in Utility Dive’s recently released State of the Electric Utility 2015 survey picked energy storage as the most important emerging technology.
“When an industry grows 40% in a year and is forecast to grow another 300% the next,” said GTM Research energy storage analyst Ravi Manghani, “the opportunities will not be limited to just one segment or one technology. They will be in the entire value chain and each step in it.”
The growth is expected to continue for at least the next five years, added Manghani, author of the GTM Research-Energy Storage Association U.S. Energy Storage Monitor 2014 Year In Review.
“After a short-term lull in utility projects in 2016, growth will resume and remain steady through 2019, resulting in over 800 MW of installations in 2019 and cumulative deployments of over 2.5 GW,” according to the report.
“The vast majority of energy storage deployments in the U.S. take place in a small number of markets with the right policy, regulatory drivers, and wholesale market designs,” explains the report, which covers only electrochemical and electromechanical storage.
Utilities and energy storage
“Utilities are embracing storage because they don’t see it as a threat,” Berkshire Hathaway Energy Vice President for Legislative and Regulatory Affairs Jonathan Weisgall recently observed. “It is not taking away revenue or electrons. It is enhancing what utilities are doing to deal with renewables.”
Examples of utility involvement, according to the report, include:
- California: PG&E, SCE, and SDG&E responses to the CPUC mandate for 1,325 MW of energy storage by 2024
- New York: ConEd and PSE&G RFPs for storage to help them defer T&D and load management infrastructure investments
- Arizona: APS and TEP 10 MW behind-the-meter procurements
- Hawaii: HECO in-front-of-the-meter and behind-the-meter procurements for grid support
- Texas: Oncor study on the value of utility-controlled storage
In addition, there are storage initiatives and financing from ERCOT, PJM, and numerous public agencies including New Jersey’s BPU, New York’s PSC, Oregon’s Department of Energy, Massachusetts’ CEC, and the U.S. Department of Energy.
Cost and technologies
Cost remains the biggest hurdle for a market that was valued at $128 million and had a weighted average system price of $2,064 per kilowatt last year, according to the report. “But cost is only one side of the equation,” Manghani said. “A lot of other factors determine whether storage is economic for a particular customer. It is also about the benefits and revenue streams that storage can provide.”
“We are seeing systems at between $1.20 and $2.50 per watt,” Solar Grid Storage (SGS) CEO Tom Leyden, whose start-up was just acquired by SunEdison, recently told Utility Dive. Only a “significant revenue opportunity” justifies adding that, which is why storage is not yet widespread.
“Price is on a downward trajectory. When the costs come down, new markets will open up,” Leyden predicted. “A 30% price reduction is possible in the next couple of years and as much as a 50% to 60% reduction in the couple of years after that.”
Lithium ion battery chemistries provided 70% of the capacity in 2014 and the other 30% was spread between flywheels, sodium chemistries, flow batteries, and emerging technologies, Manghani said. “Broadly speaking, we expect lithium ion to be the biggest battery technology deployed through 2019.”
The technology and bankability are proven, he explained. “Any technology that would dethrone lithium ion would have to prove both the technology and its commercial viability.”
Promising emerging technologies have found only pilot or early commercial deployments. “It takes two to four years of commercial data for end customers, financiers, and EPCs to buy a technology,” Manghani said. “Even those that are commercial today will take three to five years before they can compete with lithium ion.”
The opening for new technologies will be in the increasing demand for energy storage applications that require more power for longer periods. “Lithium ion chemistries have been good for 15 minutes to 2 hours to 4 hours,” Manghani said. “For anything beyond that 4 hour window, lithium ion becomes economically much more difficult. That is where emerging technologies can start to gain share.”
Applications like microgrids and capacity markets require 4 hours to 10 hours of storage. Once new technologies show they can perform in those applications, they might compete against lithium ion, he predicted. “But we are still a few years away from that.”
In-front-of-the-meter and behind-the-meter
Grid-bolstering in-front-of-the-meter energy storage is growing rapidly and constituted 90% of deployment in 2014. But the report found behind-the-meter storage deployment is growing faster and is expected to be 45% of the overall market by 2019.
Today, behind-the-meter storage is primarily used by residential customers for power back-up and system resiliency and by commercial and industrial (C&I) customers for demand charge reduction, Manghani said.
C&I customers have larger rooftop spaces closer to the grid and within robust feeder systems, larger peak period load profiles, and, most importantly, more financial motivation to adopt storage because of higher energy and demand charges, time-of-use rates, and demand response opportunities.
“For an average C&I customer, 30% to 50% of their bill is the demand charge,” Manghani said. “Any reduction storage can enable makes it more affordable.”
“Economics is the million dollar question,” Sunspec Alliance Development Director Tim Keating recently observed. “C&I is a use case for storage that you can make pencil economically now."
A big part of the reason behind-the-meter storage is growing fast is that it will serve in-front-of-the-meter grid stabilization uses, Manghani said. “It provides backup to end customers but the grid can call on aggregated systems to perform capacity or frequency regulation services.”
The recent Southern California Edison (SCE) procurement of five times the energy storage it solicited, California Energy Storage Alliance Senior Director Mark Higgins recently observed, “suggests even behind-the-meter energy storage systems can provide economically-competitive grid services.”
Leyden expects to have the capability to aggregate residential and C&I storage into a virtual storage asset for frequency regulation by the end of the year, he said. “We can aggregate residential systems in New Jersey with a commercial system in Maryland for PJM. The more aggregated, the more frequency regulation we can market.”
Storage and rate reforms
A better economic case for residential deployments may also be emerging, Manghani noted. In anticipation of the recently imposed Salt River Project (SRP) demand charge, GTM Research ran some numbers. The analysis concluded a hypothetical, utility-introduced residential rate demand charge could, under some circumstances, make solar-plus-storage economics better than solar-only economics.
“SRP is only one utility out of the 3,000 in the U.S. but it will not be the last utility to enforce a residential rate structure that benefits solar-plus-storage,” Manghani said. “Any kind of net energy metering reform that reduces the value of solar works in favor of storage.”