Batteries seen as a more than $2 billion market by 2020, but challenges remain
Energize Weekly, February 22, 2017
Battery storage has been getting a big boost from financial and market analysts who see revenues reaching more than $2 billion by 2020. Still, some renewable energy experts caution that there remain a number of hurdles the technology must overcome.
In early February, Morgan Stanley issued a report saying that the growth of battery storage is “underappreciated” by many in the utility industry. The Wall Street investment bank estimates the “addressable” market for storage at 85 gigawatts (GW) or a total of $30 billion.
If the Federal Energy Regulatory Commission (FERC) revises its rules to enable storage to be used as an energy source in the deregulated markets, which cover about two-thirds of the country, the market for storage could increase to 145 GW.
The Morgan Stanley report projects the annual demand for storage rising from the current $300 million to between $2 billion and $4 billion by 2020, with most of the investment being made for utility-scale batteries.
Morgan Stanley isn’t the only one bullish on batteries. GTM Research, a cleantech market research firm, forecasts that residential, commercial and industrial battery storage—the so-called behind-the-meter installs—will grow from the current 15 percent of the total market to 50 percent by 2021. GTM projects the 2020 market at $2.1 billion in line with the Morgan Stanley numbers.
Forecasts for the international market are also upbeat. “The Asia Pacific region is expected to see the highest growth in advanced batteries for utility-scale applications during the next 10 years, though growth is also forecast to be strong in North America and Western Europe,” according to a report by Navigant Research. Navigant pegs the 2025 market at $3.6 billion.
While theses analyses paint a picture of batteries being installed across the grid—from residential 14-kilowatt Tesla Powerwalls, at $5,500 each, to utility-scale arrays, like Indianapolis Power & Light’s $25 million, 20-megawatt (MW) installation—there remain a host of issues to be resolved that may yet limit the market.
“Most batteries are still niche applications” with utility-scale arrays being used for frequency regulation and batteries of various sizes being employed for backup in remote or difficult to serve areas, said Paul Denholm, a researcher at the federal National Renewable Energy Laboratory.
PJM, the regional transmission organization (RTO) that runs wholesale markets for an area covering all or parts of 13 mid-Atlantic and Midwestern states and the District of Columbia, allows large-scale storage facilities to bid into the short-term market which aims to balance the grid’s frequency.
In 2016, PJM said it had more than 300 MW of advance storage (which can also include flywheel storage) in place or under development, such as AES Corp.’s 32-MW Laurel Mountain facility in West Virginia.
It turns out that in the frequency market, storage, which can respond faster to grid operator signals, is more efficient than traditional generation, though it cannot last as long. PJM rules award higher compensation to fast response.
FERC orders in 2011 and 2013 opened the door for utilities to pay more for speed and preciseness of energy response. Last November, the commission proposed a rule that would clear the way for storage to participate in wholesale energy markets.
The frequency market is small. To compete in larger wholesale markets, the price of battery storage will have to come down. “Batteries need to get to the point where they compete against peaking resources,” said Denholm. Peaking plants are put online to meet peak demand and are usually the most expensive kilowatt-hours a utility generates.
Denholm said that the price batteries must reach is a moving target, but he placed it roughly in the range of $250 to $350 a megawatt-hour installed. Since 2010, the price has dropped 65 percent to about $350, according to the International Renewable Energy Agency’s 2017 REThinking Energy report.
The cost of lithium-ion batteries, the most used battery storage technology, ranges between $285 and $581 per megawatt-hour, according to a 2016 levelized cost of storage analysis by Lazard, a financial consulting and asset management firm. That represents a 12 percent decline from the price range in Lazard’s 2015 study.
By 2025, IHS Markit, a London-based industry consultant, expects lithium-ion batteries will be included in up to 80 percent of all global battery storage installations.
Pumped hydro storage, which has been the primary storage method, is still the cheapest with a price per megawatt-hour of $152 to $198 in the Lazard study.
The biggest market for lithium-ion batteries and the spur to price and efficiency improvements has been electric vehicles (EVs), with about 500,000 on U.S. roads and a total of 1.2 million across the globe, according to the U.S. Energy Department and the International Energy Agency.
EV demand will continue to be a big part of the market. Bloomberg New Energy Finance projects annual EV sales hitting hit 41 million by 2040—equal to 35 percent of global vehicle sales.
Still, even with declining prices, “batteries deployed for a single primary service generally do not provide a net economic benefit” on the grid, according to the Rocky Mountain Institute (RMI), an energy consulting group.
The institute’s study, “The Economics of Battery Energy Storage,” says that batteries will become more economically competitive not only by a decline in the price of the technology, but by “stacking” the multiple economic benefits they can provide.
Grid parity—matching the cost of one generating technology on a pure per megawatt-hour basis—is the wrong way to value batteries, said Jaime Mandel, a principal in RMI’s electricity practice. “Grid parity measurement doesn’t work because batteries can provide so many difference services,” Mandel said.
The RMI study identifies 13 potential benefits batteries can provide, spread among RTOs, utilities and customers.
For example, batteries can provide voltage support and enable energy arbitrage for an RTO, transmission congestion relief and deferral of infrastructure investments for utilities, and the ability to better manage bills, collect rooftop solar electricity and provide backup power for a homeowner.
“Batteries at their current price are cost effective today if you use them the right way,” Mandel said.
Putting a dollar value of the benefits, however, isn’t easy. RMI notes that studies of the value of transmission and distribution upgrade deferral range in studies from $50 a kilowatt-year to $350—a 600-percent spread.
“You have to be fairly skeptical about the stacking because of some double accounting,” said Denholm. He also said that those values are subject to change as the grid and rates change.
Mandel and Denholm agree that rates will be the key determinant in the future of behind-the-meter installations. A battery lets a homeowner better manage time-of-use rates, where charges increase and decline with demand, or demand charges, which are set on a customer’s peak demand.
And as rates change over time and geographically, the economics of the battery can change with them. “A battery-based storage system that is economically viable in Pennsylvania may not be viable in Texas,” the Lazard study notes.
For example, residential battery storage is getting a boost in states where utilities are seeking to reduce or abolish the net-metering credit for electricity put on the grid by residential solar units. Solar installers have been opposing the rollback attempts.
With a reduced net-metering credit, which is usually equal to the kilowatt-hour charge for residential customers, some small solar arrays may no longer be economical. Adding a battery enables a customer to gather all the electricity from a home array and avoid kilowatt-hours at the full residential rate.
“It is pretty clear that solar companies and battery companies end up on opposite ends of the net-metering debate,” said Mandel.
While residential solar and batteries may make sense in places with high electric rates and reduced net-metering credits, the market for batteries linked to renewable energy generation may not develop, said Denholm.
“Behind-the-meter batteries are all driven by rate structure and rates keeping changing,” Denholm said.
It was also thought that variable renewable energy generation—no solar when the sun isn’t shining, no wind power when the wind isn’t blowing—would need storage to enable it to be dependable and integrate into the grid.
AES’s 32-MW battery installation in West Virginia, for example, is attached to the company’s 98-MW Laurel Wind Farm.
It has been shown, however, that with high-tech computer management and sophisticated modeling and forecasting of wind and solar resources, high levels of renewable energy can be integrated into the gird without batteries, Denholm said.
Similarly, while batteries can help with peak demand, it is “easier” to use other demand strategies such as programmable thermostats, hot water heater cutoff switches and energy efficient buildings, Mandel said. Batteries would have a secondary position, though “they still have their place,” he said.
So, widespread battery deployment will depend upon whether FERC opens a path for their use in wholesale markets and then whether the price of batteries is competitive in those markets.
Electricity rate structures will also have a big impact on the battery market, and while the movement toward time-of-use rates and demand charges would appear to create opportunities for batteries, it will depend on how those rates are structured.