A week after Tesla announced it had won a tender for the installation of the world’s biggest battery storage system in Australia, Siemens and AES launched a joint venture that focuses exclusively on battery storage systems. The first comments from observers suggest that this joint venture, called Fluence, could turn into stiff competition for Tesla, and there are facts to support this suggestion.

Tesla has 300 MW worth of battery-powered storage systems across 18 countries. AES and Siemens boast a combined 463 MW of such projects across 13 countries. Tesla has a gigafactory and plans to build three more. AES has a decade of experience in energy storage systems, and Siemens has more than a century of experience in all things energy technology as well as an established presence in over 160 countries around the world.

It certainly looks like the energy storage sector just got a lot more exciting. Bloomberg’s Brian Eckhouse quotes AES’ chief executive, Andres Gluski, as saying that energy storage is “the holy grail for renewables.” Gluski is certainly right: the biggest hurdle for the wider adoption of renewable energy in the past has been the lack of reliable energy storage capacity that would solve the pesky intermittency challenge that is inherent in solar and wind power generation.

With battery-based storage, renewable energy will receive a major boost; there’s hardly any doubt about it. According to Bloomberg New Energy Finance, while there was 4 GW of battery-based storage capacity installed by the end of 2016, it is estimated to reach 45 GW by 2024.

There are three drivers to this increased adoption: reliability, sustainability, and affordability, as expressed by Siemens’ head of energy for the U.S. and Canada. This is what led Siemens and AES to join their forces, in fact, or, as Gluski put it to Green Tech Media, “We have to massify this product to continue to bring down costs. On long-duration systems, we think we’re the most competitive in the market, but we’ll be even more competitive if we’re even larger.”

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Wide-scale storage is currently the Holy Grail of researchers designing energy-storage solutions for clean energy, and scientists at Stanford University have come closer to achieving it with a new mathematical model for designing materials.

The work—conducted by researchers in the university’s School of Earth, Energy and Environmental Sciences—also could help researchers build batteries that last longer in smaller form factors, said Daniel Tartakovsky, a professor in the school and one of the leaders of the work.

“If you could engineer a material with a far superior storage capacity than what we have today, then you could dramatically improve the performance of batteries,” he said.

Tartakovsky described the model—which works with nanoporous materials, the materials widely used to develop energy storage—and how it works to Design News . These materials look solid to the human eye but contain microscopic holes that give them unique properties.

“The model connects pore characteristics of a nanoporous material, e.g., its pore structure, and operating conditions to the material’s macroscopic properties of interest, e.g., electrolyte diffusion or electric capacitance,” he explained. “This connection is then used to optimize these macroscopic properties by using the pore characteristics as decision variables.”

Until now, working with nanoporous materials has been a matter of trial and error, but the model gives materials scientists more predictability in their work, Tartakovsky said.

“We developed a model that would allow materials chemists to know what to expect in terms of performance if the grains are arranged in a certain way, without going through these experiments,” he said. “The model provides a systematic alternative to the currently used ‘trial-and-error’ strategy for materials development, which could dramatically accelerate discovery of nanoporous metamaterials with superior energy-storage characteristics.”

Indeed, by using the model, researchers can “significantly speed up design of nanoporous metamaterials with superior energy-storage characteristics, such as electrolyte diffusion or electric capacitance,” Tartakovsky said.

Tartakovsky and fellow researchers published a study on their work in the journal Applied Physics Letters .

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In this week’s news, utility scale storage is on the up-and-up, led by a new partnership between two AEE members, and Microsoft makes major deals for advanced energy. Both stories exemplify two trends we’re tracking this year: major corporations choosing advanced energy and the rapid growth of the storage market. Any way you slice it, advanced energy is on the rise!

On Tuesday morning, AES Corp. and Siemens announced the two companies are combining forces for a new joint venture: Fluence. Each company is already a global leader in energy storage, and the new venture combines the technical expertise of AES Energy Storage with the global reach and power of Siemens, both AEE members. Fluence will offer storage solutions that range from commercial and industrial to the largest utility-scale storage, and in 160 countries.

Julian Spector, writing for Greentech Media, hails the move as an “unprecedented… pre-emptive consolidation of power in a young industry,” adding that Fluence is a competitor for energy storage superstar (and media darling) Tesla.

AES Energy Storage is a long-time leader in energy storage technologies. AES is responsible for the first-ever grid-scale advanced battery energy storage solution nearly a decade ago, and operates the largest global fleet of battery-based storage installations in the world, according to the company. Earlier this year, AES Energy Storage worked with San Diego Gas & Electric to build, deploy, and manage the world’s largest lithium-ion battery storage facility.

For its part, Siemens has been no energy storage slouch. In January of this year the company, which has been building heavy-duty grid equipment for more than a century, formed a partnership with Eos Energy Storage. But the new combo will help the companies go big in energy storage. 

“We have to massify this product to continue to bring down costs,” said AES CEO Andres Gluski in an interview with Greentech Media. “On long-duration systems, we think we’re the most competitive in the market, but we’ll be even more competitive if we’re even larger.”

“Fluence will be an energy storage technology and services company, working with utilities, project developers and commercial and industrial customers across the globe,” said AES spokesman Steven Goldman in an interview with Utility Dive.

Meanwhile, Tesla is deploying the next biggest thing – that is, what will then become the world’s largest lithium-ion battery system. Tesla will work with French energy utility Neoen to install a 129 MWh battery, which will be paired with a wind farm in South Australia. On Twitter, Tesla CEO Elon Musk posted that the system will be the “highest power battery system in the world by a factor of three.”

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Sonnen has signed a contract with an Arizona homebuilder to install its energy storage systems along with rooftop solar on each residence in forthcoming developments.

This has long been a goal for the company, which aims to create a community of homeowners who produce and exchange clean energy, while performing distributed grid services. The sonnenCommunity in Germany has grown to 8,000 members and functions like its own utility. That robust vision would be hard to implement in the U.S., given the regulatory structures in place here.

Loading up a new-build housing development with storage may be the next best thing.

Including storage offsets the potential strain on the grid that comes from packing a feeder with a lot of new distributed solar. Savvy site selection can place the fleet of battery-equipped homes at locations on the grid most in need of some help.

“Your duck curve in this very particular node without storage is extreme,” said Olaf Lohr, head of U.S. business development, describing a new neighborhood packed with rooftop solar. “But we add storage to it, and we actually alleviate that problem right away.”

That sounds like a decentralized version of what utility Arizona Public Service has done with its most recent grid battery deployment. It placed two 2-megawatt AES storage systems at different points on a solar-heavy feeder in a valley northwest of Phoenix, in order to test how the location influences the system’s ability to maintain power quality and voltage control.

That feeder serves a newly built housing community that features abundant rooftop solar, encouraged by the sunny climate and the west-facing roofs that can catch the late afternoon sun.

Sonnen has not finalized an agreement with a utility yet to make use of its forthcoming home network. Theoretically, the fleet of battery systems could deliver aggregated peak capacity, renewables integration, demand response or ancillary services. In practice, such virtual power plants are still being demonstrated in the U.S., especially when it comes to residential-sited systems. In Germany, Sonnen has already been doing it for several years.

The company wasn’t ready to reveal the name of the homebuilder partner, but described it as a progressive builder that typically constructs 200 homes a year and aims for 300 in 2018. The project is expected to break ground in Q4.

Customers who move into the homes will automatically join the sonnenCommunity. What exactly that means for a U.S. customer is still being decided, but it will include assistance on one’s energy bill, said Senior Vice President Blake Richetta. 

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Korean battery maker Samsung SDI is upbeat on growing demand for energy storage, driven by an increasing number of countries pushing for energy self-sufficiency, along with a drop in battery prices making it economically feasible.

The global energy storage system, or the ESS market, is predicted to see the fast growth in the coming years. According to the US market research firm Navigant Research, it is forecast to grow to 4.3 gigawatt hours this year, around a 50 percent jump from the previous year, and grow around 60 percent on an annual average by 2020 to 14.8 GWh. 

ESS captures energy produced for use at a later time, aiming to improve energy efficiency. It can effectively save renewable energy such as thermal power, solar energy, wind power and geothermal power, which otherwise are affected by bad weather or climatic conditions. 

On growing demand for energy storage worldwide, Samsung SDI’s ESS business turned black for the first time in the fourth quarter of last year and has continued to see strong sales since. 

“We expect to continue to see strong sales (this year) on growing energy storage demand as many nations have recently moved forward on climate change to reach Paris climate accord goals,” said Park Se-woong, vice president of Samsung SDI’s ESS team in an interview with The Korea Herald.

The Paris climate accord, which was agreed by 195 nations in late 2015, is designed to reduce carbon emissions in order to lower the earth’s temperature. This has led to many nations seeking energy self-sufficiency through renewable energy. 

“Alongside the growing demand, the drop in battery prices is also making ESS have a better return on investment than power grid,” he added. 

This year, Samsung plans to focus on the two largest ESS markets, the US and Europe. 

“The energy storage markets in the US and Europe have been fast growing due to their ageing power grid and efforts to seek energy self-sufficiency,” he said. 

Samsung SDI joined the largest battery-based energy storage project in the US in partnership with the US power giant AES Corp. and other companies from June to December of last year. It supplied 240 megawatt-hour ESS batteries, around 70 percent of total 350 MWh, the largest-ever supply for ESS projects. 

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The energy storage industry needs better financing to break out of its early stages. So far, commercial project financing is becoming more widely available, but residential financing has barely gotten started.

The high upfront cost of storage makes it hard for behind-the-meter customers to purchase out of pocket, and they can’t call on the kind of capital available to utilities or large power producers. For financiers, meanwhile, energy storage poses several risks: It’s a relatively new technology with emerging business models and revenue streams, both of which are subject to the influence of shifting tariff structures.

“If the energy storage market is going to grow beyond the early adopters, there’s going to have to be more widely available, low-cost financing,” said Brett Simon, a behind-the-meter storage analyst at GTM Research, who recently published a report on storage financing.

Here are the key indicators of where storage financing stands today.

Commercial financing is growing, with a clear pathway to success

The pool of project financing is swelling. It jumped from almost nothing in 2015 to $796 million in 2016, and the storage financing in 2017 hit 51 percent of that amount by mid-May. That money is going almost exclusively to commercial projects, although a growing cohort of lenders now at least cover residential storage.

The minimum internal rate of return needed to attract financiers ranges from the high single digits to the low 20 percent mark, according to Simon’s latest research on the topic. The bulk of financiers are looking at the low to mid-teens.

Contracted revenue streams can cut the cost of capital for a project, the study notes. Capacity payments from utilities are an early form of this, and many utilities are examining new ways for distributed storage to provide grid services. Such an arrangement provides the lender with greater certainty that the storage installation will bring in revenue.

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ST. PAUL — A new report from a Minnesota university shows adding energy storage may be a cost effective way to help meet the state’s electricity demand.

University of Minnesota’s Energy Transition Lab presented its report to the Minnesota Public Utilities Commission this month, Minnesota Public Radio reported. The commission recommended the state pursue energy storage pilot projects.

Natural gas power plants are typically used during peak demand because they can be ramped up and down quickly. New natural gas plants generating about 1,800 megawatts are planned for the state by 2028 to help meet the peak demand, said lab director Ellen Anderson.

Anderson said the cost of building more solar arrays with batteries is more cost effective than building a conventional plant because the technology is now cheaper and there are federal tax credits, which can be applied to facilities.

Minnesota has also adopted policies that can give solar energy projects higher value than fossil fuel energy projects because of the environmental impact.

“What we’re seeing is we’re right on that precipice where now it’s actually today viable to put some in the ground,” said Chris Clack with Vibrant Clean Energy.

The report also found the state could better utilize wind energy resources. Wind turbines are set to produce less electricity if the energy supply exceeds the demand.

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When it comes to energy storage, some of the most skeptical entities in the power sector are often utilities.

Most recognize the promise of storage to provide grid services and even help defer some investments as an alternative to traditional grid upgrades. But start talking about batteries as an alternative to generation — such as replacing gas peakers — and many utilities get sheepish.

That’s the case even with utility leaders in energy storage. When Tucson Electric Power signed a breakthrough 4.5¢/kWh contract for a solar-plus-storage facility, executives steered away from comparing its capabilities to gas peakers.

Storage still has some “significant limitations” to peak shaving, “which can easily be longer than four hours,” the duration of the TEP battery, said Carmine Tilghman, the utility’s senior director for energy supply. Gas peakers and storage are different products and “should not be compared with each other and as replacement for one another.”

AES seems to be cut from a different cloth. On Tuesday, the utility holding company announced its energy storage subsidiary would enter into a joint venture with Siemens to form Fluence, a commercial- and utility-scale storage provider with more than 460 MW of storage deployed or awarded today.

During a speech in Washington, D.C., announcing the partnership, AES CEO Andres Gluski situated storage as a potential replacement for all kinds of bulk power infrastructure, from transmission to generation. In a subsequent interview with Utility Dive, he said AES’s 10 years of experience in the storage space give him the confidence that other power providers may lack.

“If you look at Southern California Edison, the 100 MW, 4-hour system competed against peaker plants,” he said. “We’ve shown it to be cost effective today. It’ll only become more cost effective as time goes on.”

Gluski was touting AES’s 100 MW, 400 MWh Alamitos project, awarded in 2014 in a local capacity RFO from the utility. That project is set to go into service in 2021, and since then the company has won other major projects, including deploying the largest lithium-ion battery in service and contracting for a 100 MWh battery to pair with a solar project in Kauai.

“Now it’s kind of like the asset test, if you think about what Kauai is doing. The prices will vary, depending on location and what the competing energy is,” he said. “But in 10 years of experience, I think we’ve proved that and our systems are still up and operating … and still making money for us.”

Fluence, the new joint venture with Siemens, will have access to 160 countries. Siemens’ SieStorage product focuses on commercial and industrial applications, while AES is a utility-scale specialist, so the venture will allow the company to run “the whole gamut” of large storage offerings, Gluski said.

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Battery lifespan to match generation assets