Study: Get ready for a surge of grid batteries

Source: By Peter Behr, E&E News reporter • Posted: Wednesday, March 11, 2020

Utilities are planning a massive increase in storage battery installations in the next five years, accelerating opportunities for greater wind and solar generation across the U.S., according to a market survey by Wood Mackenzie and the Energy Storage Association.

At the end of 2019, battery storage in utility and residential markets stood at 899 megawatts, a blip compared with the total U.S. electric power plant capacity of over 1.1 million MW. But the forecast issued yesterday predicts that as much as 1,452 MW of new battery capacity could be added this year, with utility installments around 60% of the total, joined by a sharp increase in “behind-the-meter” residential and commercial battery purchases.

From there the surge of storage additions at utilities, businesses and homes grows, the report said, as prices on current lithium-ion batteries continue to fall. The report projects that annual battery investments will reach a total of 7,317 MW by 2025, with two-thirds of that by utilities, bringing the total battery installations nationwide to over 35,000 MW.

The two organizations reported that nearly 104 MW of utility-scale storage capacity was added in last year’s fourth quarter, a 160% jump from the prior year. The electricity supplied by batteries increased by 44% over the period, led by new projects in the Mid-Atlantic-based PJM Interconnection.

Kelly Speakes-Backman, the association’s CEO, used the findings to make a pitch for federal support. “The electricity system of today and tomorrow relies on energy storage expansion, inclusion and integration. To accelerate its resilience, reliability and economic benefits, it is critical that federal lawmakers enact a standalone federal energy storage tax credit,” she said in a statement.

Battery installations already have wind at their back, Wood Mackenzie reported. “The one big trend we’ve noticed in recent months is that utilities across the country, when they do their long-term planning, are increasing adding storage or renewables plus storage,” analyst Brett Simon said.

“In 2017 and before, the only utilities planning for this were in states you’d expect — California, Hawaii. A lot of it was driven by state mandates,” he added.

Now, the firm’s review of utilities’ integrated resource plans submitted to state commissions and storage proposals in grid operators’ queues shows projects in 47 states. “The only exceptions are Idaho, Vermont and Tennessee,” and Vermont has an existing battery storage installation, Simon said.

“Some of the development in queues may not occur. A fair amount won’t get built,” Simon said. But it will be a boom in any event, he added.

Behind the trend is a prediction of continued declines in storage prices, with Wood Mackenzie charting a 24% drop in midrange prices from today’s levels by 2022. The dollar figure wasn’t included in the public summary of the market report.

It is a hard figure to pin to the board, said Wesley Cole, an analyst with the Energy Department’s National Renewable Energy Laboratory (NREL) in Golden, Colo.

“I’ve seen and heard a lot of different things about where costs are going. Lots of opinions. I wouldn’t say there is consensus,” he said.

NREL surveyed 25 private firms last June that assess battery storage cost trends. The high estimate for 2030 was $337 per kilowatt-hour, about 10% below the 2018 figure, while the low estimates averaged $124, a decline of two-thirds.

Those prices are still far above costs of new generation. The U.S. Energy Information Administration’s current estimated “levelized price” for construction and operation of a new natural gas combined-cycle plant in 2025 is $37 per kWh, with around $34 for onshore wind and solar and $115 for offshore wind.

Moving fast

EIA estimated that by 2023, utilities would add 2,500 MW of storage, compared with 4,000 MW predicted by Wood Mackenzie. Cole explained that EIA’s figure comes from a computer model that can undercount the potential for new storage in a region like PJM with a large overcapacity of generation.

“The market is moving really fast,” Cole said. “Unless you’re keeping up with latest data, it’s easy to get behind.”

A combination of a new solar or wind farm with a four-hour storage backup is becoming a popular choice for utilities seeking to retire old coal- or gas-fired power plants that come on to supply demand only in a few hours of peak demand, Simon said.

Tapping batteries for four to six hours is very similar to the way gas peaker units are often used, Luis Ortiz, vice president for microgrids at Anbaric Development Partners, told E&E News last year (Energywire, July 1, 2019).

The technology is getting cost-competitive at a time when some states want to see the peaker units gone to reduce emissions, particularly when disadvantaged communities are in the emissions path, Ortiz said.

Much bigger storage installations, or storage and new transmission lines, are required to overcome dayslong droughts in wind speeds or sunshine, experts say. If wind or solar replaced a 2-gigawatt nuclear power plant and batteries provided the sole backup, 6 to 8 GW of battery storage would be required, Wade Schauer, Wood Mackenzie director of Americas power research, said last year.

But technology is creating new uses for storage, including a hybrid system of batteries, solar power and advanced digital controls, according to the Energy Systems Integration Group, a Reston, Va.-based research association of experts from energy companies and government laboratories (Energywire, Jan. 30).

Instead of connecting separately to the grid at their particular prices, a solar unit and battery partner would bid into power markets as a combined resource, closely managed by the system’s software controls to maximize potential power delivery, ESIG said. That could significantly expand uses of battery storage beyond the peaking role.