NEW YORK–(BUSINESS WIRE)–Eos Energy Storage (“Eos”) – pioneer of the safe, ultra-low cost Znyth^® battery technology – today announced a partnership with Siemens to integrate, install and service energy storage solutions.

“Working with such an established energy industry leader like Siemens is an exciting step for us and the energy storage industry,” said Eos CEO Michael Oster. “By combining Eos’ cost and performance advantage with Siemens’ capabilities in system integration and project execution, we are able to offer solutions that reduce risk and complexity for the customer while setting a new benchmark for energy storage reliability and cost-effectiveness.”

The Eos Aurora^® 1000│4000—a 1MW|4MWh DC battery system—is being sold today at $160 per usable kWh for the full DC system with performance guarantees supporting up to 20 years of continuous operation with minimal maintenance. Eos packages its patented Znyth^® technology in a modular, pre-integrated, outdoor-rated enclosure called the Energy Stack^TM.

Leveraging this novel design, Eos and Siemens have jointly productized an energy storage system including AC power conversion and controls that enables modular installation and ease of maintenance, lowering cost throughout the project development cycle. This joint product offers utilities an economic alternative to conventional system upgrades, renewable energy developers a means of dispatchable hybrid power, and commercial customers load management savings paired with enhanced power quality and reliability.

“Our goal is to standardize and productize energy storage projects with focus on reliability and return on investment for the customer,” said Siemens VP Brian Dula. “This process starts with modeling and analytics to optimally size the energy storage asset and carries all the way through project implementation and performance guarantees. By offering a solution with supporting services, Siemens will help customers realize the full benefits of the Eos Aurora battery.”

Together, Siemens and Eos are able to offer energy storage solutions for a broad range of grid-connected and off-grid markets. Collaborative testing and product validation is setting the stage for MW-scale installations in the first half of 2017—including a California Energy Commission funded project with Pacific Gas & Electric (PG&E), demonstration of a behind-the-meter, commercial and industrial product at the University of California at San Diego, and a first-ever utility microgrid installation combining the Eos Aurora with on-site solar and diesel generation.

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Jobs in New York’s energy storage sector have grown to approximately 3,900 – a 30% increase from 2012 through 2015, according to a new report from the New York State Energy Research and Development Authority (NYSERDA).

The agency says New York’s commitment to clean energy helped spur this strong growth, and storage will advance the state’s  50% by 2030 clean energy standard, as storage technology can save power generated from solar, wind, and combined heat and power (CHP) systems for later use.

The report projects that by 2030, New York’s energy storage industry could realize annual global revenues between $5.6 billion and $8.7 billion. In addition, jobs could reach between 17,300 to 26,800 employees (a consistent growth scenario versus a delayed market adoption scenario).

“New York State has become a hub for energy storage technologies – creating new, skilled technology jobs and meeting the needs of utilities, building owners, manufacturers and other large power users,” says John B. Rhodes, president and CEO of NYSERDA. “Under Gov. Cuomo’s Reforming the Energy Vision to create an energy system that is cleaner, more affordable and more resilient, strong growth continues for storage technology and investments.”

NYSERDA says it has invested in more than 50 energy storage technology development projects across the state. It is also working to reduce soft costs associated with distributed energy storage systems by 33% in five years.

In December, NYSERDA hosted a two-day, on-site power conference and expo, which brought together stakeholders in solar, energy storage and CHP to facilitate discussions about when and how the technologies can work together to help New York meet its clean energy goals.

Along with several partners, NYSERDA established the New York Battery and Energy Storage Technology Consortium (NY-BEST) in 2010 to help advance the state’s energy storage industry. The consortium now includes Fortune 500 companies, startups, universities, national research centers and laboratories spanning all facets of the energy sector, NYSERDA says.

“NY-BEST is pleased that our efforts to grow the energy storage industry in New York State are producing positive results,” says Dr. William Acker, executive director of NY-BEST. “Thanks to the state’s clean energy policies and strategic investments, New York State has created an unmatched ecosystem for energy storage companies seeking to grow their businesses, and we look forward to continuing to help foster the growth of this industry in New York.”

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Over the next eight to nine years, energy storage capacity in developing countries is expected to skyrocket from 2 gigawatts (GW) today to more than 80GW, according to a new report by the World Bank Group.

The report, “Energy Storage Trends and Opportunities in Emerging Markets,” indicates the annual growth in energy storage capacity will exceed 40% each year over the next decade.

The study, commissioned by the International Finance Corporation (IFC) and the World Bank-administered Energy Sector Management Assistance Program (ESMAP), indicated the largest energy storage markets are expected to be China and India.

The researchers believe that 78GW of new solar and wind generating capacity was installed globally in 2016, and that 378.1GW is projected to be installed over the next five years.

“Energy storage will play a crucial role in helping to meet demand for low-carbon electricity in developing nations,” the report said. “By 2020, these countries will need to double their electricity generation, according to the International Energy Agency (IEA), and by 2035 will account for 80% of the total growth in energy generation and consumption globally.”

While the cost for deploying renewable energy systems continues to fall, integrating technologies such as photovoltaic rooftop systems and solar farms into regional grids will require energy storage in the form of batteries and other technologies for load continuity.

Those storage technologies include mechanical systems such as flywheels, compressed air or pumped hydro; electrochemical storage, such as lithium-ion (li-on) and flow battery technology; and thermal systems like phase-change technology. Phase-change tech uses materials such as molten salt to store heat from concentrated solar farms for later release in steam generators.

Tesla CEO Elon Musk announced earlier this month his company is now mass producing li-ion batteries for both commercial and residential use. His first “gigafactory” outside Reno, Nev. has a footprint of 1.9 million square feet of manufacturing space. Musk already plans to build other gigafactories around the world.

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A new residential energy storage pilot seeks to better understand how batteries installed in homes can be used at the neighborhood level by grid operators to absorb solar power generation excesses during the day and discharge them when needed later in the day.

A partnership between battery manufacturer Moixa, electricity distributor Northern Powergrid, and the community energy company Energise Barnsley aims to put the idea to the test with a new pilot. Specifically, 40 homes will have Moixa lithium-ion batteries installed, including 20 x 2 kWh batteries and another 20 x 3 kWh batteries.

Simon Daniel, CEO of Moixa, said:

“Solar homes with batteries can halve their electricity bills, and this solution will become increasingly popular as costs of storage and PV fall.

“We are working closely with Northern Powergrid and this project will deliver insights to develop incentives which we hope will allow us to roll out solar plus storage to tens of thousands of homes in their region, by creating a business case for homeowners to invest and also by increasing the number of solar connections allowed on each substation.”

These 40 batteries and homes will be linked into a Virtual Power Plant (much like what Next Kraftwerk is doing today but on a smaller scale) which the utility can then utilize to absorb power when solar production is peaking. Conversely, at night when the sun isn’t shining on all those glorious solar panels, or anytime demand exceeds production, the utility can tap into this Virtual Power Plant to supply power to the grid.

Most of the homes in the pilot already have photovoltaic (PV) solar installed (30 of the 40 homes) which will allow the pilot operators to better understand how residentially installed solar PV can play well with residentially installed lithium-ion batteries.

In this pilot, the batteries will be installed at no cost to the residents, with all funding provided by Northern Powergrid in an effort to support the masses of solar being deployed by Energise Barnsley.

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New research from the World Bank Group indicates energy storage capacity will increase 40-fold in developing countries over the next 8-9 years; growing to 80GW from 2016’s 2GW capacity.

The report, commissioned by IFC and the World Bank-administered Energy Sector Management Assistance Program (ESMAP), says energy storage deployments in emerging markets are expected to grow more than 40 percent each year in the coming decade.

The largest energy storage markets during this timeframe are expected to be China and India.

Energy storage will play a crucial role in helping to meet demand for low-carbon electricity in developing nations. By 2020, these countries will need to double their electricity generation according to the International Energy Agency (IEA), and by 2035 will account for 80 percent of the total growth in energy generation and consumption globally.

The report says the uptake of battery and other stationary storage technologies would enable emerging markets to roll out more solar power and wind energy, with reduced need for fossil fuel-fired power plants to provide backup when conditions are unfavourable. Storage can also help overcome other grid management challenges associated with variable energy generation from these sources.

“By dramatically expanding the capacity to store energy, these technologies will help countries meet their renewable energy targets, support the demand for clean energy, and help bring electricity to the 1.2 billion people who currently lack access,” said IFC Executive Vice President and CEO Philippe Le Houérou.

It’s unlikely to be a smooth journey, with significant barriers and challenges ahead to overcome. These include challenges relating to awareness, competition, operational practices, regulatory issues, political and economic instability and procurement.

However, the report states the most important factor in the energy storage market achieving its full potential may be the availability of low-cost financing for project development, as high upfront costs would otherwise limit growth.

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From the perspective of both renewable-energy advocates and electric utilities, grid-scale energy storage offers many potential benefits.

By storing energy in battery packs for later use, energy storage can make intermittent renewable sources like solar and wind into more reliable forms of power.

It also helps utilities “balance” the grid by absorbing excess energy during periods of low demand, and releasing it during periods of peak demand.

Yet energy storage has not been tested on a large scale by U.S. utilities.

Until now, that is.

California now has three completed energy-storage sites, constituting the biggest test yet for the technology, notes The New York Times (subscription required).

The state passed an energy-storage mandate, but development did not pick up until a massive 2015 gas leak in Aliso Canyon, a large-scale environmental disaster that also cut off fuel to local power plants.

The leak started at a Southern California Gas Co. storage facility in October 2015, and lasted several months.

In that time, it released greenhouse-gas emissions equivalent to the annual emissions of 1.7 million cars.

Infrastructure company AES built an energy-storage array for utility San Diego Gas & Electric (SDG&E) in Escondido, California, about 30 miles from San Diego.

Billed as the largest installation of its kind in the world, it uses lithium-ion batteries from Samsung, and reportedly has enough capacity to power about 20,000 homes for four hours.

AES is also installing a smaller energy-storage array for SDG&E in El Cajon, which is also near San Diego.

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Canadian underwater energy storage company Hydrostor is eyeing US$1 billion of contracts to replace decommissioned U.S. peak power plants in the next two or three years, its chief executive said.

So-called “peakers,” electrical generators which are turned on only when demand is highest, are a critical but expensive element of the electricity grid.

Hydrostor and its engineering partner AECOM are targeting dozens of mostly coal-powered facilities of at least 100 megawatt capacity across the U.S. that either shut down in 2016 or will shut this year.

Hydrostor buys off-peak electricity to compress air it stores underwater in balloon-type accumulators. It then reverses the process to generate power and feed it back into the grid when demand is high.

“We are now by far the lowest cost storage solution, we can be built at scale, we’ve got our partnerships in place and we’re going to start marketing it here in the next month or two,” Curtis VanWalleghem, Hydrostor’s chief executive, said.

Hydrostor will compete for the attention of utilities against battery companies and new, more efficient gas-powered facilities.

“Most of the utilities in the U.S. that are starting to get their feet wet with storage are typically going with these battery plays, mostly because they’re a little more flexible,” said Craig Sabine, a strategic advisor for utilities at Navigant, a consultancy.

Utilities may also prove reluctant to turn away from gas given years of record shale production which pushed prices in 2016 to their lowest since 1999.

“The silver bullet has yet to be defined,” said Richard McMahon of the Edison Electric Institute, which represents U.S. investor-owned electric companies. “There’s a place for a lot of these technologies and certainly there remains a place for gas peaking when you’ve got those conditions, low gas prices,” he said.

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The Bay State could soon follow the Bay Area as a leading battery boomtown.

The Massachusetts Department of Energy Resources (DOER) decided, at the close of 2016, that it would set an energy storage target. Now it has six months to figure out what that number should be and how to implement it, following the timeline set by legislation last summer. Once complete, this will be only the third state-level target after California and Oregon.

California’s mandate gave it a decisive lead in attracting storage companies and deploying the technology in homes, businesses and on the grid. Massachusetts currently has very little storage deployed, but it is already home to a cluster of storage startups that spun off from research at MIT. With an effective target, Massachusetts could set itself up as the second hub of the U.S. storage industry, while streamlining the operation of its grid and the integration of new renewable generation.

Finding the right target, though, requires a careful balancing of competing goals.

“DOER should assure the target is large enough that substantial, relevant experience is gained by all, but not so large that it becomes unworkable and a substitute for the fully functioning market,” wrote Phil Giudice, CEO and president of Cambridge-based storage company Ambri, in a letter to DOER Commissioner Judith Judson in December. 

DOER isn’t starting from scratch here. The department had a hand in the State of Charge report from September, which comprehensively analyzed the value of storage for the Massachusetts grid and concluded that up to 1,766 megawatts of storage installed by 2020 would maximize savings for ratepayers. Storage can reduce the state’s system costs like peak capacity, transmission and distribution upgrades, overall energy prices, integration of intermittent renewables, and ancillary grid services that smooth out the momentary differences between supply and demand.

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CALGARY — The rise of renewable power has created a need for energy storage that companies are fulfilling with underwater balloons, multi-tonne flywheels and decades-old designs.

“Where renewables go, storage will follow,” said John Wright, project manager at Northland Power.

The need for energy storage comes from the temporary and sometimes unpredictable nature of renewable energy. The wind doesn’t always blow and the sun doesn’t always shine.

Power companies and utilities have been looking to compensate for that with what amount to giant batteries and smooth out delivery, storing energy in times of low demand and distributing it when demand is high.

Northland has been developing a 400-megawatt pumped storage project that takes the form of an old flooded mine, sitting on a plateau just outside of Marmora, Ont.

The roughly $900-million project in eastern Ontario pumps water up into the mine pit when there’s extra energy, and then lets it run out through a turbine when more energy is needed.

Alberta’s plan to replace coal-fired power plants with 5,000 megawatts of new renewable energy — more than all of the renewable energy currently online in Ontario — has prompted TransAlta Corp. to dust off half-century-old plans to expand its Brazeau hydroelectric project.

Similar to Northland’s Marmora project, Brazeau would be a storage operation that would allow the company to pump water back up to the reservoirs of the existing hydro project, which is about 200 kilometres west of Edmonton.

TransAlta currently uses the project’s 355 megawatts of hydro to cover peak demands, while the expansion would add 600 to 900 megawatts of capacity and increase its flexibility.

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