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Battery storage is gaining a foothold in the California peaker plant market previously served by fast-acting natural gas generators.

Replacing gas peakers notches an early victory for the energy storage industry, but it is not sufficient to decarbonize the grid. Short-duration batteries have a physical limitation: They cannot deliver power indefinitely, and longer-duration options are rare at commercial scale.

That raises the question of what comes next as California, joined by a growing cohort of states, moves toward a legislative mandate of zero-carbon grid power by midcentury.

Nick Chaset grapples with that question as the CEO of East Bay Community Energy, a local organization empowered to source clean electricity for Alameda County, across the bay from San Francisco. His organization recently signed a contract to replace a decades-old jet-fuel-burning peaker in downtown Oakland with a 20-megawatt, 4-hour-duration lithium-ion battery plant.

Despite its smaller capacity and limited run time, that battery will step in to provide local capacity in place of the fossil-fueled asset.

“Right now, there’s still tremendous opportunity for the 4-hour[-duration] investments, which we’re going to continue to make,” Chaset said in an interview after the contract-signing ceremony. “What you’ll see is, through 2030 probably, it’s storage, 4- and 6-hour batteries, [that] gets you where you need [to be].”

After that, the path is less certain.

Near-term vision: Build the batteries
Peaker plants make easy targets for the clean energy industry. They act as a form of physical insurance against blackouts, costing ratepayers hundreds of millions of dollars even though they rarely participate in the grid. When they do, they burn dirtier than other resources.

Solar and wind power cannot replace peakers, because they do not dispatch on command. Batteries can, however, and they enjoy certain advantages when it comes to siting in load pockets like urban areas where a new thermal plant may not survive environmental permitting. Moreover, batteries can participate in grid activities when they are not needed for peak power, defraying their cost as a reliability asset.

The way the world gets its electricity is undergoing a rapid transition, driven by both the increased urgency of decarbonizing energy systems and the plummeting costs of wind and solar technology. In the past decade electricity generated by renewables in the U.S. has doubled, primarily from wind and solar installations, according to the Energy Information Administration. In January 2019 the EIA forecast that wind, solar and other nonhydroelectric renewables would be the fastest-growing slice of the electricity portfolio for the next two years. But the intermittent nature of those sources means that electric utilities need a way to keep energy in their back pocket for when the sun is not shining and the winds are calm. That need is increasing interest in energy-storage technology—in particular, lithium-ion batteries, which are finally poised to be more than just a bit player in the grid.

For decades pumped-storage hydropower, a simple process that features reservoirs at different elevations, has been the dominant large-scale energy-storage method in the U.S. To store energy, water is pumped into the higher reservoir; when that energy is needed, the water is released into the lower reservoir, flowing through a turbine along the way. Pumped-storage hydropower currently accounts for 95 percent of U.S. utility-scale energy storage, according to the Department of Energy. But as efficiency and reliability have improved, and manufacturing costs have tumbled, lithium-ion batteries have surged. They account for more than 80 percent of the U.S.’s utility-scale battery-storage power capacity, which jumped from just a few megawatts a decade ago to 866 megawatts by February 2019, the EIA says. A March 2019 analysis by Bloomberg New Energy Finance reports that the cost of electricity from such batteries has dropped by 76 percent since 2012, making them close to competitive with the plants, typically powered by natural gas, that are switched on during times of high electricity demand. To date, whereas batteries have largely been used to make brief, quick adjustments to maintain power levels, utilities in several states, including Florida and California, are adding lithium-ion batteries that will be able to last for two to four hours. Energy research firm Wood Mackenzie estimates that the market for energy storage will double from 2018 to 2019 and triple from 2019 to 2020.

Lithium-ion batteries will likely be the dominant technology for the next five to 10 years, according to experts, and continuing improvements will result in batteries that can store four to eight hours of energy—long enough, for example, to shift solar-generated power to the evening peak in demand.

But getting to the point where renewables and energy storage can handle the baseline load of electricity generation will take energy storage at longer timescales, which will mean moving beyond lithium-ion batteries. Potential candidates range from other high-tech options, such as flow batteries, which pump liquid electrolytes, and hydrogen fuel cells to simpler concepts, such as pumped-storage hydropower and what is called gravity storage. Pumped-storage hydropower is cheap once it is installed, but it is expensive to build and can be used only in certain terrain. Similarly simple is the concept of gravity storage, which purports to use spare electricity to raise a heavy block that can later be lowered to drive a turbine to generate electricity. Although a few companies are working on demonstrations and have attracted investments, the idea has yet to take off. Other options are still under development to make them sufficiently reliable, efficient and cost-competitive with lithium-ion batteries. There were only three large-scale flow-battery storage systems deployed in the U.S. by the end of 2017, according to the EIA, and utility-scale hydrogen systems remain in demonstration stages. The U.S. government is funding some work in this arena, particularly through the Advanced Research Projects Agency–Energy (ARPA-E), but much of the investment in those technologies—and in energy storage in general—is happening in China and South Korea, which have also ramped up storage research.

(Reuters) – Nevada’s largest utility NV Energy will procure 1,200 megawatts (MW) of solar electricity paired with batteries, or enough to power about 228,000 homes, as it seeks to double its renewable energy resources and move away from fossil fuels.

The addition of energy storage to all three projects underscores how important – and cheap – batteries have become as utilities seek to extend the working hours of their solar facilities.

“The energy during the day time when the solar panels without a battery produce power, though valuable, is not as valuable as the energy when the sun goes down in the summer when air conditioners are running at full capacity,” Tom Buttgenbach, chief executive of 8minute Solar Energy LLC, which is developing one of three new solar and storage projects for Berkshire Hathaway Inc unit NV Energy, said in an interview on Tuesday.

The three solar projects will more than double the utility’s renewable energy by 2023, NV Energy said in a statement late on Monday.

The projects include a 690 MW array with a 380 MW battery storage system on federal land near Las Vegas. The Gemini Solar project is being developed by Quinbrook Infrastructure Partners and Arevia Power, NV Energy said.

The Southern Bighorn Solar & Storage Center, developed by 8minute, will combine a 300 MW solar facility with a 135 MW lithium ion battery and will be located on the Moapa River Indian Reservation. The battery will provide 4 hours of storage to extend the power plant’s effectiveness into the evenings.

8minute said the project will deliver power for about $35 per megawatt-hour, less than the cost of electricity generated by natural gas or coal.

The final project is a 200 MW plant with a 75 MW battery storage system on the Moapa Band of Paiutes Indian Reservation. It is being developed by EDF Renewables North America.

In April, Nevada passed a law requiring utilities to source 50 percent of their power from renewable sources by 2030. NV Energy said it has a long-term goal of serving customers with 100 percent renewable energy.

The US National Renewable Energy Laboratory (NREL) has put numbers on the significant potential for energy storage to replace peaking capacity on the grid in the US, albeit with an understanding that as the peak changes, the goalposts will also move.

NREL has said in a report just-published that around 70GW of peaking capacity in the US – from a total base of about 261GW – could be served by energy storage systems of four, six and then eight hour durations.

However, as has been pointed out previously to Energy-Storage.news by the likes of redT executive Scott McGregor in the past, once clean energy starts tackling the time during which demand peaks, the peak itself widens as a window during the daytime or – more likely – early evening.

As more and more storage is installed to allow for peak mitigation, so the peak could become a longer event. McGregor was talking specifically about demand reduction for commercial businesses in that instance, but it appears the same could broadly hold true for peaking capacity.

NREL said that some 150GW of peaking capacity is set to be retired within 20 years in the US, with natural gas turbines coming to the end of their lifetimes, but it cannot be assumed that this can all be replaced immediately or directly with energy storage.

“The step from 4 hours to 6 hours is relatively small (about 8 GW), because the first 4 hours of storage typically widens the peak to about 6 hours, leaving little room for 6-hour storage. The 8-hour step is much larger (about 34 GW), leading to a total potential for combined durations of about 70 GW,” the authors of the report, ‘The potential for battery energy storage to provide peaking capacity in the United States’, wrote.

Appetite for renewables remains the ‘X Factor’
However, that takes into account mostly a business-as-usual scenario, and in the event that larger and larger shares of renewable energy go onto the grid and change net loads even further from their present day shapes – which is hardly unlikely – that potential figure could see a large increase, NREL said.

Long-duration energy storage solution provider Highview Power has developed a modular cryogenic energy storage system, the CRYOBattery, that is scalable up to multiple gigawatts. This technology reaches a new benchmark for a levelized cost of storage (LCOS) of $140/MWh for a 10-hr, 200-MW/2-GWh system. Highview Power’s systems can enable renewable energy baseload power at large scale, while also supporting electricity and distribution systems and providing energy security.

“This is a pivotal moment for the renewable energy industry and for anyone who wants to deploy large amounts of renewables,” said Javier Cavada, president and CEO of Highview Power. “As more and more renewables are added to the grid, long-duration, giga-scale energy storage is the necessary foundation to make these intermittent sources of power reliable enough to become baseload. Not only does our CRYOBattery deliver this reliability and allow scalability, it is proven, cost-effective, and available today.”

Highview Power’s proprietary cryogenic energy storage technology uses liquid air as the storage medium and has the ability to provide voltage support, frequency regulation and black start capabilities. Unlike competing long-duration technologies, such as pumped hydro-power or compressed air, Highview Power’s CRYOBattery can be sited just about anywhere. The CRYOBattery has a small footprint, even at multiple gigawatt-levels, and does not use hazardous materials.

Alex Eller, senior research analyst with Navigant Research, said, “Long-duration technologies such as cryogenic energy storage will become increasingly necessary for an electricity system to transition from a primary reliance on conventional fossil fuel generation to a grid dominated by variable renewable generation from solar and wind.”

Cavada said Highview Power’s CRYOBattery can enable grid operators to maximize renewable penetration without needing fossil fuel generation to make up for intermittency. “This makes replacing gas peaker power plants with a combination of solar, wind, and energy storage a viable reality and truly sets the stage for a future where 100% of the world’s electricity comes from clean energy sources,” he said.

A new $3.5 million energy storage system went online last month in Ashburnham, Mass., continuing a statewide expansion of systems designed to ease pressure on the electric grid at times of peak demand.

Why it matters: In January, Massachusetts became the first state to offer incentives for battery systems, with the approval of a $2 billion state energy efficiency plan. The program is expected to support the installation of 30–34 MW of storage capacity during its 3-year term, on top of 190 MW from other operating and planned projects.

How it works: Behind-the-meter energy storage is typically paired with renewables, allowing for the capture of excess wind or solar energy. The stored energy can be used during periods of peak demand — to alleviate strain on the electric grid — or when the wind is not blowing or the sun is not shining.

Details: The plan draws on recommendations from an economic study performed by the Applied Economics Clinic. Its reports, presented to the state’s Department of Energy Resources and Energy Efficiency Advisory Council, concluded that the cost benefits of battery storage should qualify it for efficient energy incentives.

Both commercial and residential customers will be able to sign up for 5-year contracts with their utility provider for new battery storage installations.
At the end of each year, incentives will be paid out based on how much the storage system was able to offset use of the grid.
What to watch: Massachusetts has one of the country’s largest energy efficient budgets, at $620 million a year — alongside California ($1.4 billion) and New York ($450 million).

The state is making good progress toward its energy storage goals: 200 MW by 2020 and 1000MW by 2025.
As of April, New York has offered $280 million in incentives to energy storage companies.
As these states continue to realize the benefits of behind-the-meter storage, others may begin to include batteries in their own incentive policies.

AES Alamitos, a unit of The AES Corp., announces the groundbreaking of a 400 MWh battery-based energy storage system for Alamitos Energy Center as part of a larger modernization and replacement project of the existing AES Alamitos Generating Station.

The energy storage facility in Long Beach will provide up to 400 MWh of local energy to ensure power flexibility and reliability for Southern California Edison (SCE) customers, while helping the state meet its target of 100 percent clean energy by 2045.

While the AES Alamitos facility was procured specifically to provide power at times of peak demand, it will also support grid modernization, increase the integration of renewable energy, and lower costs and greenhouse gas emissions.

Supplied by Fluence, a energy storage and technology services provider, the storage used for the project will include the company’s Advancion 5 batteries and control systems; when fully charged, the batteries will be able to supply power to tens of thousands of homes in milliseconds.

AES Southland was awarded a 20-year power purchase agreement (PPA) by SCE in 2014 to provide 100 MW of interconnected energy storage. It is part of a $2 billion repowering initiative in Long Beach to replace aging natural gas peakers with a combination of efficient combined-cycle gas capacity and battery energy storage, which is now a viable alternative to replace traditional thermal generation to meet peak power demands.

Together with the AES AEC combined-cycle gas turbine (CCGT), this project will result in more than $132 million in local purchases, 1.48 million hours in construction-related work, and a payroll of over $315 million.

At completion – projected for late 2020 – the new AEC will not only be cleaner and more responsive to California’s energy needs, but it will also contribute between $12.3 and $14.6 million annually to the local economy.