WASHINGTON — Speakers at the GridWise Alliance’s GridCONNEXT conference last week left no doubt: Electric storage is long past the “tipping point.”

Moderator Ram Sastry, vice president of infrastructure and business continuity for American Electric Power, had posed the question: “Are we going to see large-scale deployment of energy storage systems? And if not, what’s stopping that?”

“I think we’re at or past that tipping point,” responded Andy Marshall, practice director for distributed energy resource management at Landis & Gyr. “I think you see the flexibility of storage and its ability to get deployed relatively quickly. You have not only the stuff that’s going on down in Australia, but you also have the things that are happening most recently in California.”

On Dec. 1 — the first day of summer for Australia — Tesla turned on a 129-MWh lithium ion battery, the world’s largest,   to help the nation’s fragile electric grid. California deployed 100 MW of storage in just six months in response to natural gas constraints following the Aliso Canyon lea

Praveen Kathpal, vice president of AES Energy Storage, said “the technology is mature,” noting that his company entered the business a decade ago. AES claims 500 MW of storage already deployed or in development.

“There haven’t been any components that needed to be invented for any of the deployments that we’ve done, because they’re all based on lithium ion battery technology, which was commercialized 25 years ago and has benefited from its use in the consumer electronics and transportation sector,” Kathpal said.

“The tipping point we see in storage is really meshing with some of the other megatrends facing our industry right now. We have the accelerated growth in renewables, and we also have the electrification of more sectors including transportation.”

Kathpal predicted new storage technologies will break below the current pricing floor for lithium ion. “So, 10 years from now, do I think we’ll have a commercially available storage technology that’s below $100/kWh? Sure. And that’s exactly why at AES the technology platform we’ve developed is forward compatible with technology change.”

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The agreement aims to provide energy storage solutions to the hybrid electric and electric vehicle industry.

An ultracapacitor is a high-power energy storage device that has a recharge time of 2-3 seconds and over one million life cycles.

The two companies believe that ultracapacitors will bridge a gap in hybridisation and electrification efforts within the automotive sector.

They have the ability to reduce CO2 emissions as well as increase performance and be cost-effective for manufacturers.

“We are excited to announce the agreement with Sumitomo Corporation Europe, it was a natural fit from the start,” commented Taavi Madiberk, CEO of Skeleton Technologies.

“Sumitomo´s world-class distribution network and technical expertise in electrification enable us to expand our footprint in the automotive sector and tap into the company’s relationships with key players in the transportation industry.”

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Construction on Australia’s first utility-scale wind, solar and energy storage hybrid project to be connected to the national grid is about to start near Hughenden in northwest Queensland.

Australian developer Windlab put out a similar release in October, but construction on the roughly 60MW plant is now due to start today. The project is owned by Windlab and its equity partner Eurus Energy Holding Corporation of Japan.

The innovative AU$160 million Kennedy Park Energy will take around 12 months to construct and is expected to be completed and start feeding clean energy into the network by late 2018, according to Windlab’s executive chairman and chief executive Roger Price.

He added: “This is an industry first that will produce and feed clean renewable energy into the grid with much greater consistency and reliability from a combination of solar, wind and battery storage. It’s also an important and valuable demonstration of how renewable energy can be used to cost effectively meet most network demand for power – day and night. We believe that this style of hybrid configuration will be increasingly used, particularly in remote locations and emerging markets, as the world transitions to a clean energy future. We are excited about the opportunities that the expertise gained from this pioneering project will present as we seek to replicate it across selected locations in Australia and Southern Africa.”

The park includes 43MW of wind, 15MW of solar on single-axis trackers, and two lithium-ion batteries. This includes 56,000 solar panels and twelve Vestas V136, 3.6MW wind turbines.

Kennedy Energy Park secured finance from the Clean Energy Finance Corporation (CEFC) and the Australian Renewable Energy Agency (ARENA), as part of ARENA’s Advancing Renewables Programme.

Utility CS Energy will purchase the energy from Kennedy Energy Park under a 10-year power purchase agreement.

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Sometimes, there can be too much of a good thing.

Every so often, from California to Germany, there’s news of “negative electricity prices,” a peculiar side effect of global efforts to generate clean energy. Solar farms and wind turbines produce varying amounts of power based on the vagaries of the weather. So we build electrical grids to handle only the power levels we expect in a given location. But in some cases, there’s more sun or wind than expected, and these renewable energy sources pump in more power than the grid can handle. The producers of that power then have to pay customers to use up the excess electricity; otherwise, the grid would be overloaded and fail.

As we build more and more renewable-power capacity in efforts to meet the emissions-reduction goals of the Paris climate agreement, these situations will become more common. Startups led by entrepreneurs who see this future on the horizon are now looking for ways to make money off the inevitable excess clean electricity.

On a mildly chilly day in April, with the smell of poo in the air, I met one of these startups at a sewage-water treatment plant in Copenhagen, Denmark. Electrochaea takes carbon dioxide produced during the process of cleaning wastewater, and converts it into natural gas. That alone would be impressive enough; if we want to stop global warming in its tracks, we need to do everything we can to keep CO2 from entering the atmosphere. But Electrochaea has also figured out a way to power the whole enterprise with the excess green energy produced during particularly sunny and windy days that otherwise would have gone to waste, because there would have been no way to store it.

In other words, when scaled up, Electrochaea’s process could be an answer to one of the biggest problems of the 21st century: energy storage, while also making a dent in cutting emissions.

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Energy storage is increasingly being included in utilities’ chief planning tool: the integrated resource plans (IRP). That inclusion is a sign that utilities are beginning to see the value and benefits that energy storage brings.

“Utilities are becoming more active players in the energy storage market,” Brett Simon, energy storage analyst at GTM Research, told Utility Dive in an email.

A significant number of utilities now include energy storage in their IRPs, including Arizona Public Service, Tucson Electric Power, Florida Power and Light and Puget Sound Energy.

PG&E’s contract with EDF RE does not come as a surprise, Simon said. Like California’s other two investor owned utilities, PG&E is required to procure energy storage under AB 2514 that was passed in 2010.

Some foreign utilities have also shown an increased interest in the storage market over the last 12 to 24 months, Simon says, citing ENGIE and Enel.

ENGIE North America and Holyoke Gas & Electric in October said they plan to build a 3 MW, 6 MWh storage project at a Massachusetts solar farm that used to house a coal plant. Also in October, Enel told Bloomberg that the company is looking for energy storage acquisitions.

“This is a trend I’d expect to continue as storage economics continue to improve and utilities begin to explore new technologies to ensure effective system operations in the face of a changing grid,” Simon said

In the PG&E deal, EDF RE will build, own and operate a portfolio for PG&E that will include behind-the-meter battery storage projects for commercial and industrial customers in PG&E’s service territory.

The aim of the projects is to help C&I customers to lower their electric bills by reducing their demand charges and maximizing consumption during off-peak hours, as well as bringing in revenue by using storage to provide services to California’s wholesale power market.

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Massachusetts’ Baker-Polito administration hasawarded $20 million in grants to 26 energy storage projects in the state.

Recognizing the benefits energy storage holds for the commonwealth, as well as the strength of the submitted projects, the administration says it doubled the available funding from the initial $10 million commitment. The awarded projects will benefit 25 communities and draw in $32 million in matching funds, helping to grow the state’s energy storage economy.

The grants were awarded as part of the Baker-Polito administration’s Energy Storage Initiative (ESI) Advancing Commonwealth Energy Storage (ACES) program, funded by the Department of Energy Resources (DOER) through Alternative Compliance Payments (ACP) and administered by the Massachusetts Clean Energy Center.

The awardees are EnerNOC; UMass-Amherst; Massachusetts Municipal Wholesale Electric Co. (two projects); UMass-Boston; GE; Boston Medical Center; Borrego Solar Systems (two projects); Advanced Microgrid Solutions; Greenlots; Martha’s Vineyard Transit Authority; Tesla (two projects); Solect Energy; NuGen Capital; UMass Memorial-Marlborough Hospital; Reading Municipal Light Department; NextEra Energy; National Grid; Ameresco; Taunton Municipal Light Plant; Sunrun; Constellation; WH Bennett; and West Boylston Municipal Light Plant.

The announcement was made by Gov. Charlie Baker, R-Mass., during an event at UMass Memorial – Marlborough Hospital. The critical-care facility will use funding received under the grant program to integrate a 400 kW solar canopy and energy storage system.

“The development and deployment of energy storage projects will be vital to the commonwealth’s ability to continue leading the nation in energy efficiency,” says Baker. “Funding these storage projects is an investment in our energy portfolio that will reduce costs for ratepayers and help create a clean and resilient energy future.”

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The mega industrial lithium-ion energy storage system (ESS) has been ordered by Korea Zinc, a metal smelting company at a cost of 50 billion won, or around $45 million, reports Inhabitat.

Hyundai also points out their ESS will be nearly 50 percent bigger than Tesla’s 129 megawatt-hour grid storage battery in South Australia. Hyundai says their ESS will be operational sometime in February 2018.

Bloomberg New Energy Finance senior associate Ali Asghar said, “Musk has set a benchmark on how quickly you can install and commission a battery of this size,” and that plummeting costs are “making them a compelling mainstream option for energy storage applications in many areas around the world.”

And despite the growing competition to install mega-industrial ESSs, this is not the story. For as Asghar notes, the battery-storage industry has become increasingly important, not only for places that have less access to traditional fossil fuel energy sources but to industries that are heavily energy-intensive, like a metal smelting plant.

Need for “peaker” plants solved

Even as the cost of battery storage systems continues to drop globally, one of the biggest advantages in an industrial-sized ESS is the savings realized from not needing to build “peaker” plants that operate just a few hours a day.

Wind and solar power can be considered intermittent power sources because they may not be efficient when the wind is not blowing or the skies are cloudy. This is where storage batteries smooth out the need to have a traditional power plant as a backup.

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The nation’s largest utility holding company and a major lithium supplier are partnering up to create a new company designed to connect investors with well-researched opportunities in the energy storage sector.

Exelon Corp. and Albemarle Corp. announced Wednesday that they were founding investors in Volta Energy Technologies. The new Napierville, Illinois-based firm seeks to connect technical and product development know-how with investment mechanisms.

 “The energy sector is undergoing a transformation,” said Chris Crane, president and CEO of Exelon. “We must help lead the nation through this change by investing in the next big innovations that provide the best commercial and customer solutions. Exelon launched and invested in Volta because we operate at the forefront of energy innovation, and energy storage represents an important next frontier.”

Exelon owns and operates utilities which provide electric and gas service to millions of customers in the Midwest and eastern U.S. Units include Commonwealth Edison, Baltimore Gas & Electric and PECO, among others.

The worldwide advanced battery and storage market is projected to rise to more than $100 billion within a decade, according to some reports. Over the next year, Volta will seek other investors who have energy storage as a key element of their business strategy.

“Investing in Volta is a strategic priority for us,” said Luke Kissam, CEO of Albemarle Corporation. “Many expect that there will be exciting innovations in lithium battery technology in the future, and we want to be a part of any process that might identify new technologies to power the potential of clean energy solutions. We are excited about ultimately creating value in the markets, and for Albemarle, through our partnership with Volta.”

Traditional venture capital funds often lack the expertise and patience required to advance innovations from lab to market, and public research institutions are not charged with commercializing their work. Volta’s model bridges these gaps and offers a solution.

“Volta’s model is built to identify the winning technologies and businesses in the rapidly evolving battery and energy storage sectors. This enables major, market-moving companies and other investors to choose wisely the technologies that will shape our future energy system,” said Volta founder and CEO Jeff Chamberlain.

“During my 24 years in the private sector and at national labs, I saw firsthand how challenging it is for a single entity to develop a new physical technology—or for a single investor to identify the right opportunity, let alone take it to market,” Chamberlain said. “Volta brings together a team of battery storage and investment experts to tap into the unmatched capabilities of the U.S. national laboratory system to identify and overcome deal-killing technical challenges.”

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U.S. energy-storage capacity surged 46 percent in the third quarter, mainly due to a single big project in Texas, the biggest source of wind power.

Power companies and developers added 41.8 megawatts of storage systems, including a 30-megawatt utility-scale project in Texas, according to a report Thursday from GTM Research and the Energy Storage Association. California added 8.4 megawatts of residential and commercial systems. The industry installed 28.6 megawatts in the third quarter of 2016.

Driven by regulatory demands and sharp price declines, energy-storage is becoming more common. Prices for lithium-ion battery packs have fallen 24 percent from 2016 levels, according to Bloomberg New Energy Finance. Utilities including Exelon Corp., Duke Energy Corp. and American Electric Power Co., meanwhile, are increasingly receptive to storage projects, which potentially will facilitate wider adoption of wind and solar power.

GTM forecasts that 295 megawatts will be in operation in the U.S. by year-end, up 28 percent from 2016. And more is coming. GTM projects the U.S. energy-storage market will be worth $3.1 billion in 2022, a seven-fold increase from this year.

“Energy storage is increasingly acknowledged in utilities’ long term resource planning across the country,” Ravi Manghani, GTM Research’s director of energy storage, said in a statement.

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ISO-NE is working to ensure that its wholesale markets can accommodate an expected exponential growth of energy storage resources, an RTO manager said Tuesday.

“We want to be sure that our wholesale markets are favorable to all resource types equally, so when we think about energy storage, we want to make sure it fits in the box,” Carissa Sedlacek, ISO-NE director of market development, said during a Dec. 5 energy storage seminar hosted by the Northeast Energy and Commerce Association in Boston.

With 20 MW of energy storage already interconnected in ISO-NE and nearly 80 MW in the interconnection queue, the RTO is adjusting some of its market rules to accommodate the new and flexible resources coming online, Sedlacek said. (See ISO-NE Plans for Hybrid Grid, Flat Loads, More Gas.)

“How is that energy storage facility going to operate?” Sedlacek said. “Is it going to operate at full capacity for one hour, or is it going to operate at quarter-capacity for four hours? How is it going to respond if it’s coupled with wind or solar? Is it going to be there for longer durations? Is it going to be used more in the winter than in the summer? These are the types of questions we ask in the planning department as we consider new resources, especially something like energy storage.”

Spreading the Risk

ISO-NE predicts energy storage providers will largely focus participation in the RTO’s ancillary services market because many of them are not prepared to assume the financial burden of qualifying for the Forward Capacity Market (FCM) — or to confront the risk of coming up short on a capacity supply obligation (CSO), Sedlacek said.

“If you get a megawatt CSO that you cannot achieve, there will be a financial penalty,” Sedlacek said, noting that penalties go into effect June 1, 2018, leaving some storage developers “a little gun shy” about offering into the FCM. She noted that solar and wind participants in the FCM don’t typically attempt to qualify for their nameplate capacity, but only a percentage of nameplate (usually 40 to 42%) to ensure their obligation is achievable.

“Because under the [FCM], you’re on the hook to provide those megawatts,” she said.

Sedlacek explained how energy storage developers might hedge their risk by pursuing incentives offered for over-performing in the FCM.

“So you can figure out what your output would be over a four-hour period, because that’s what you have done analysis on and you think might actually last for a shortage of that [capacity amount],” she said. “That’s the megawatts you want to actually take on as the CSO, but be happy to take on additional megawatts or have more output on real shortage events, days or hours, and kind of scoop up the additional revenue.”

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