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.

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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.

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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.

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This series of articles explores both grid scale and behind-the-meter (BTM) grid optimization strategies and the implications for our customers. The first article in the series set the stage by providing the regulatory framework and outlining the delivery framework being implemented to enable 150 megawatts (MW) of both grid-scale and behind-the-meter demand assets over the next three years in Eversource’s Massachusetts service territory.

Battery storage is often described as the “killer app” for the grid due to its versatility and ability to provide multiple services. This second article describes how utilities can re-program that “killer app” of storage to reduce costs for customers and reduce emissions. Future articles in this series will explore the technology, processes, and customer facing aspects of successful distributed energy resource programs. The last article in this series will offer a glimpse of how behind-the-meter and front-of-the-meter assets come together in the grid of the future.

Utility-scale storage

for utilities to consider both utility-scale and behind-the-meter (i.e. customer-sited) storage. In Massachusetts, Eversource has already received approval for two utility-scale storage projects. The first project is located on Cape Cod: a 25-MW/38-MWh project that will provide increased reliability and resiliency for the Outer Cape communities of Provincetown, North Truro, Truro and Wellfleet. The second project is a 4.9-MW/20-MWh system located on the island of Martha’s Vineyard. This battery system will reduce greenhouse gas emissions created by diesel-fired generators during times of high energy demand. These projects will be beneficial for customers by lowering costs by avoiding traditional investments, increasing reliability, allowing for additional renewable generation, and reducing emissions by decreasing the need to run older expensive, dirty fossil fuel generation during peak times.

Behind-the-meter storage

In addition to utility-scale storage, utilities should consider customer-sited storage as well. Future articles in this series will discuss the synergistic effects of coupling utility-sited storage with customer-sited storage. Eversource expects to help deploy over 20 MW of customer-owned and sited storage that can potentially enhance grid operations. Taking a holistic approach to analyzing storage and which type of technology is best suited for each customer allows for a more customized approach to storage. For instance, lithium ion batteries may be a good fit for certain facilities that see temporary spikes in energy use from air conditioning or process loads. However, thermal storage, such as ice storage or phase change material, may be a better solution for a customer with cold storage or a food processing facility.

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BOSTON, June 25, 2019 /PRNewswire/ — 2018 was a remarkable year for stationary energy storage. According to IDTechEx’s research report, governments and policymakers around the world are beginning to wake up to the value batteries can offer to the grid, both in terms of flexibility and decarbonization. Over 6 GWh was deployed, and market leaders, such as Tesla, expect to double their deployments for 2019.

The progress is thanks, in no small part, to falling Li-ion battery costs, driven by the economies of scale of the electric car industry: plug-in passenger electrics topped five million on roads globally at the beginning of 2019. Indeed, as costs have fallen, projects with longer duration battery systems have become feasible (many new grid-level projects are now four hours). This has created opportunities for storage developers: in some scenarios, it has even enabled the displacement of gas peaker plants, for grids aiming to fully decarbonize. As detailed in the new IDTechEx report, “Batteries for Stationary Energy Storage 2019–2029,” enormous projects are underway.

For example, the famous ‘100 MW (120 MWh) in 100 days’ challenge from Elon Musk to the South Australian government, a previous world record and now operational, is a fraction of the planned 730 MWh system Tesla will install in Moss Landing, California to help replace three aging gas plants.

The U.S. has led the industry for a number of years—a sizable mandate from California, coupled with big-budget financial incentives, have underpinned the country’s deployments, as well as the batteries procured for frequency response in PJM’s territory from 2012-2017 (now saturated). In 2018, landmark rulings like FERC Order 841, ambitious decarbonization and renewables targets in multiple states, and growing momentum behind state-wide energy storage mandates will pave the way for the future of energy storage in the country.

The global picture is also changing: both China and South Korea topped 1 GWh in yearly deployments in 2018, with India also commissioning some of its first large-scale projects. With such rapid progress, teething problems have emerged: to meet the sudden demand in South Korea, ESS makers compromised on quality, leading to a government shutdown of hundreds of public battery systems that spontaneously caught fire. The issue was reported by Korean news outlets to be faulty battery management systems. States in the U.S. with energy storage mandates and targets. Source: IDTechEx “Batteries for Stationary Energy Storage 2019–2029.”

Despite hiccups, the ambitious levels of renewables integration in many of these countries will nevertheless require massive amounts of energy storage to manage moving forward. The new IDTechEx report, “Batteries for Stationary Energy Storage 2019–2029,” details the leading countries now and in the future.

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Legislation to increase VAT rates for solar and battery storage technologies for households was put forward yesterday, despite strong opposition from industry.

Under the new law proposed by HM Revenue and Customs (HMRC), the VAT for new solar and storage products will increase from 5% to 20% from October.

The legislation is put forward on the same day MPs debate the adoption of the net zero carbon emissions target for 2050.

In contrast, coal sold as a fuel for domestic use will continue to receive a reduce VAT rate of 5%.

The Renewable Energy Association (REA) believes the HMRC proposals should be reconsidered, particularly considering public support for renewable energy was recently announced to have reached an all-time high of 84%.

It adds the VAT hike could push back the decision of households and businesses to install solar with battery storage “by years”.

Dr Nina Skorupska, Chief Executive of the Renewable Energy Association said: “The VAT proposals will create a barrier to British homes and businesses who are seeking to take action on climate change and reduce their bills by installing solar with battery storage.

“With 84% of the public supporting renewable energy and a further 80% concerned about climate change, the government should be doing all it can to install these technologies rather than enacting barriers.”

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General Electric will demolish a California natural gas-fired plant with 20 years remaining in its useful life, deeming the plant “uneconomical” as inexpensive solar and wind grab a larger share of power in the state.

The Inland Empire Energy Center (IEEC), a 750 megawatt plant, is slated for closure by the end of the year. GE told Reuters, “We have made the decision to shut down operation of the Inland Empire Power Plant, which has been operating below capacity for several years, effective at the end of 2019.”

The complete Inland Empire Energy Center Decommissioning and Demolition Plan has been published on the commission’s website. It notes that IEEC is selling the project site to Nova Power “for the purpose of developing a battery energy storage system (BESS).”

The plant relies on GE’s H-Class turbines, which is now considered a legacy technology. Experts told Reuters the turbine has a number of technical issues. GE noted the plant is now “uneconomical to support further.”

GE’s plant was first approved in 2003 and only came online about a decade ago, according to the California Energy Commission. Now the plant is set to close, only having gone through one-third of its designed useful life.

California is aiming to get 100% of its electricity from carbon-free sources by 2045, with 50% of its electricity generation to come from renewables by 2025. A report earlier this month noted the state is now putting so much solar power into the electrical grid that there’s a surplus at times. Starting next year, all new homes in California must come with solar panels.

The state’s own goals, combined with falling renewable costs, are putting the squeeze on fossil fuels. As the decommissioning and demolition plan notes:

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The Hawaiian Electric Industries, the parent company of Hawaii’s investor-owned utilities, has officially kicked off the second phase of its renewable energy procurement agreement, whose roots date back to 2017.

Of the Hawaiian Islands, phase 2 procurement focuses on Oahu, Maui and Hawaii, with the former two given clear renewable generation and battery storage targets, while Hawaii’s figures are a bit more up-in-the-air.

All of the energy and capacity designations in this request for proposals are made in annual MWh for generation, while the accompanying storage is outlined in MW and MWh. The proposed RFP calls for Oahu to add 1,300,000 MWh of renewable generation, as well as 200 MW of storage (438,000 MWh). For Maui, those numbers are 295,000 MWh generation and 40 MW of energy storage (58,000 MWh). Hawaii will add somewhere between 70,000 and 444,000 MWh generation, with a ballpark of 18 MW of battery storage.

Using average capacity factors for Hawaii, the actual MW figure – how much generation the utilities are seeking – can be extracted. For Oahu, that figure is just over 148 MW. Maui isn expected to be on the receiving end of 50 MW, while Hawaii’s deployment is unclear so far and will be somewhere between 8 and 51 MW.

Another odd piece of this RFP is the storage seems to be more paramount of a goal than the renewable generation. This is supported contextually by the previous mention of energy figures, and by some wording in the RFP.

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24M, currently thought to be one of the leaders in developing an advanced form of lithium-ion batteries which promise increased energy density, has struck a deal with Kyocera for initial production of cells for stationary storage applications.

Energy-Storage.news interviewed some of 24M’s leadership team in March this year, when the company, spun out of MIT’s labs by founder Yet-Ming Chiang, claimed to have exceeded an energy density of 350Wh per kilogramme for semi-solid lithium-ion battery cells.

While admitting that the technology is still at the early stages of its commercialisation journey, 24M said then that it is looking to establish a 100MW pilot production plant by the end of this year.

Kyocera, headquartered in Japan’s old capital, Kyoto, and known for its historic production of ceramic goods and latterly high tech products for a range of markets including solar PV, is already an investor in the US start-up. 24M said in a release on Friday that Kyocera is now constructing production facilities for pilot production of cells, aimed at the residential solar-plus-storage market, which is rapidly growing in Kyocera’s home country. The pilot production line is in Osaka, in the west of Japan and home city to many of the country’s battery big-hitters, including Panasonic and Sanyo Maxcell.

“Kyocera considers the unique 24M SemiSolid approach the emerging standard for lithium-ion battery manufacturing. The ability to cost-effectively manufacture advanced lithium-ion batteries can enable Kyocera to expand residential sales throughout Japan,” Kyocera senior executive officer Masahiro Inagaki.

Taking lithium into advanced and long duration territory
In an in-depth interview with this site at the time of that March announcement, 24M’s execs including CEO Rick Feldt said that the ‘Dual Electrolyte’ tech the company has developed could be applied for manufacturing processes for different types of lithium-ion battery, including lithium iron phosphate (LFP) and nickel manganese cobalt (NMC).

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