The rapidly growing U.S. energy storage industry deployed 71 megawatts and 234 megawatt-hours of capacity in the first quarter of 2017.

Now, Canada is showing signs of life with a 12.8-megawatt/52.8-megawatt-hour energy storage project to be built and installed by Powin Energy.

It will be the largest energy storage project in Canada when operational.

Powin has joined with Hecate Energy to build and install the project at two sites in Ontario, using a modular 140-kilowatt element to construct the systems. The project applies energy storage to frequency regulation, voltage control, and reactive power support.

The Independent Electricity System Operator (IESO) is employing these projects as part of its long-term energy plan and expects the systems to be on-line by the end of September 2017. That’s one of the clear advantages of energy storage: fast deployment.

The company building this system has experience in rapid installations; Powin deployed a 2-megawatt/9-megawatt-hour storage system in less than six months to help compensate for the Aliso Canyon natural gas leak in Southern California Edison territory. (Tesla, Greensmith Energy and AES Energy Storage completed even bigger projects for the Aliso leak in six months’ time.)

“When IESO announced 34 megawatts of Phase 1 procurement back in July 2014, it was the largest such procurement of energy storage in North America, of which the Hecate project was the single biggest award. Since then, the project, along with the remainder of Phase 1 projects, haven’t become operational yet. It almost seems like eons ago in storage years,” said Ravi Manghani, director of energy storage research at GTM.

“From Powin’s perspective, the delay couldn’t have worked any better,” Manghani explained. “Back in 2014, Powin was still an early-stage company throwing everything at the dartboard, but since then it has received investment from SFCE (parent company of Suntech), and Powin has slowly but surely started winning contracts in California and the Pacific Northwest — and now this 52-megawatt-hour contract in Canada.”

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The solar industry is no longer just talking about pairing energy storage with solar generation.

An increasing number of solar-plus-storage projects have been cropping up around the country, as lithium-ion prices drop lower and customers get more comfortable with storage technology. The AES plant in Kauai set a record-low price in January, only to be beaten by Tucson Electric Power’s sub-4.5 cents per kilowatt-hour PPA announced in May — proving this technology isn’t just for islands and remote microgrids anymore.

For the large developers in particular, storage makes the solar product more appealing to a utility by giving the power plant flexibility and mitigating its effects on grid operations. On the islands of Hawaii, storage has already become necessary for adding major solar capacity; on the mainland, its value increases along with renewable penetration.

To get a handle on just how extensive the interest in storage-backed solar is, I got a list of the 10 largest utility-scale solar developers from my colleagues at GTM Research and tracked down the storage status of each one.

Seven of the top 10 solar developers have incorporated storage into their business strategy, and have either deployed storage alongside PV or are pursuing hybrid installations. The remaining three did not comment on how storage fits into their plans.

“This is well beyond one developer — this is really a trend we’re seeing in the industry,” said Colin Smith, a solar markets analyst at GTM Research. “Solar-plus-storage has become a forced differentiator in the industry.”

First Solar: Bidding on storage

The thin-film solar specialist first invested in energy storage in 2015, when it joined a $50 million investment round in German startup Younicos. At the time, First Solar CTO Raffi Garabedian commented, “As the promise of storage continues to evolve, we are eager to understand how it will broaden our own power plant offerings.”

These days, the No. 1 U.S. solar developer routinely permits new projects in the western U.S. for the possible addition of storage, because so many customers are asking about it, said Scott Rackey, head of PV-plus-storage development at First Solar.

“It’s a small cost to gain the optionality later,” Rackey said.

First Solar has been bidding on solar-plus-storage, including several projects at the scale of 100 megawatts of PV with 100 megawatts of battery capacity. The ideal ratio varies depending on the local grid, Rackey noted: the Southeast tends to have more appetite for PV generation during the day than Arizona, for instance, where oversupply of nondispatchable PV is becoming a challenge.

“It’s really become cost-effective in roughly the last year or year and a half for dispatchable PV,” Rackey said. “We can deliver energy comparable to or less expensively than a new-build fossil fuel plant.”

Expect some storage news from this company, then, in the months to come. First Solar, by the way, prefers the svelter acronym “PVS,” rather than the cumbersome hyphenations of “solar-plus-storage.”

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Sharp Electronics Corp.’s Energy Systems and Services Group and CivicSolar, are offering Sharp’s SmartStorage energy storage system through its distribution network of solar PV installers.

Sharp and CivicSolar’s first project will be with technology developer and systems integrator Forecast Energy.

The project features a 120 kW/160 kWh SmartStorage system plus a 313.5 kW solar power system and Forecast Energy’s proprietary forecasting platform that has been installed at Channel Lumber, one of the largest lumber companies in the San Francisco Bay Area.

Sharp’s energy storage solution paired with solar PV systems can reduce energy usage for commercial properties. Sharp’s SmartStorage system is designed to pull power from the SmartStorage batteries rather than from the utility at the times of highest demand, which are the most expensive rates, and is particularly suited for properties in parts of California where commercial utility customers are paying up to 50 percent of their energy bills toward demand charges. Channel Lumber paid $172,385 in demand charges alone over a one year period.

A detailed analysis of Channel Lumber’s energy usage profile estimates that the solar plus SmartStorage system will bring $160,466 in energy and demand savings annually — an estimated 62 percent reduction in Channel Lumber’s total bill. Forecast Energy selected Sharp’s SmartStorage system and was the integrator and installer for the entire project.

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Batteries — whether they’re powering a smartphone or storing energy on the grid — take a beating.

Repeated charging and discharging causes all kinds of wear and tear on the devices we increasingly rely on to keep our gadgets, cars and renewable energy sources running. But what if batteries could repair themselves automatically and fix on-the-fly the cracks that lead to dead laptop batteries, the limited range of electric carsand other modern woes?

That’s the idea behind the work of a team led by two professors at the University of Illinois Urbana-Champaign (UIUC). They’re taking self-healing materials research and applying it to a novel subject area: energy storage. The hope is that a better understanding of how nanoparticles bind and come undone will lead to more reliable, longer-lasting and higher-capacity batteries.

“The idea was to try to take some of the self-healing work we’ve done in plastics and bring it into the battery world, because batteries do have all these reliability issues,” says Nancy Sottos, a professor of materials science and engineering, and one of the lead researchers on the project. “There’s a lot of cracking and chemical changes that go on in the battery that are, in general, undesirable. And of course what you see in your devices is basically they’re just not charging anymore.”

A breakthrough in battery technology is a sort of Holy Grail in today’s era of mobile communications and distributed energy. Consumers demand more and more from their portable devices, and energy storage is seen as a key ingredient for widespread renewable energy deployment. In short, better batteries would make it easier for utilities and grid operators to manage the variable flows of power from intermittent wind and solar energy sources.

The UIUC team — led by Sottos and Scott White, a professor of aerospace engineering — introduces a unique nanoparticle composite material into a key part of lithium-ion batteries, the energy-storage technology that dominates personal electronics and plays an increasing role in transportation and electricity.

In May, the team published a study in the journal Advanced Energy Materials, finding that their experimental technology mitigated a lithium-ion battery’s typical deterioration, retaining 80 percent of its initial capacity after cycling through its charge 400 times.

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Giants of the UK energy sector are to work within a new collaborative group aimed at enabling significant cost reductions for the electricity system through the use of energy storage applications.

The Energy Systems Innovation Platform (ESIP) has been unveiled today by emissions reduction advisory group, the Carbon Trust and brings together utilities Centrica, DONG Energy, SSE, Scottish Power, Statoil and Wood Group’s Clean Energy division.

The companies will work together to solve what they see as “key issues” currently preventing a more cost effective transition to a low carbon energy system by developing new business models.

Andrew Lever, director of innovation at the Carbon Trust, said: “There is now general consensus that the UK energy market needs to be revamped so we can embrace a flexible and more decentralised energy system. However, the fragmented nature of the energy market is driving fragmented decision making and many investments are led by technology, not market needs.

“We now have a window of opportunity to foster new business models and put in place the regulatory mechanisms that will give investors the confidence to stop chasing market distortions and focus on the long term.

“The formation of ESIP is indicative that no one organisation can solve this issue alone and a collaborative approach is essential to deliver the biggest benefit to society as a whole.”

Representing almost half of the UK’s electricity supply market and with initial support from the Scottish government and the Foreign and Commonwealth Office (FCO), the initiative will tackle regulatory barriers which many believe have held back the development of UK storage.

It will also seek greater transparency around the decision making made across the UK energy system concerning the services storage can provide. According to Lever, this includes the choices made across DNOs, Ofgem, National Grid and government which he said “needs to be joined up and transparent to ensure the right direction, rules and signals are given to the market”.  

It is hoped this will help ESIP develop the long term business models necessary to encourage stronger investment and reach the potential of greater flexibility in the UK energy system.

Last year the Carbon Trust led a study which found that the UK could be saving up to £2.4 billion (US$3.05 billion) every year by 2030 if flexibility solutions such as energy storage were integrated into the UK electricity system.

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SaltX Technology and CSP and integrated energy systems provider Aalborg CSP have signed off on a non-exclusive joint development agreement to develop and commercialise an integrated energy storage solution for Concentrated Solar Power.

The energy storage system will be based on SaltX’s technology for large-scale energy storage, known as EnerStore.

A first prototype of the storage system is expected to be developed later in 2017, with both companies planning to secure a commercial pilot plant during 2018.

Karl Bohman, CEO of SaltX Technology, said: “SaltX and Aalborg CSP complement each other perfectly – SaltX with its cutting-edge technology, and Aalborg CSP with its strong brand, global solar project portfolio and experience to engineer and build integrated energy systems.

“The market for Concentrated Solar Power (CSP) is expected to explode over the next three years, especially in China, Africa and India. It is therefore important to quickly position ourselves and to accelerate the development of EnerStore.”

Over the next few months, both companies will begin jointly developing a solution that integrates the SaltX EnerStore technology into Aalborg CSP energy systems. The solution will then be marketed and sold to Aalborg CSP’s target customers worldwide.

Peter Badstue Jensen, executive vice president of Aalborg CSP, added: “With the development of EnerStore we expect the competitiveness of our integrated energy systems to increase, allowing us to offer even better feasibility and improved return on investment for our customers.

“The future will see more hybridised energy systems and together with SaltX we will be able to offer a more cost-effective, on-demand renewable energy solution than our competitors. We see this as a long-term partnership where we can grow together in this rapidly developing market.”

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The first quarter was the biggest quarter ever in terms of energy storage installations, but it could also be the biggest quarter of the year, according to the latest version of the U.S Energy Storage Monitor released by GTM Research and the Energy Storage Association.

The first-quarter Energy Storage Monitor recorded 234 MWh of storage installations in the first quarter, a 944% increase compared with first-quarter 2016.

In terms of power rating, 71 MW of storage projects were deployed in the first quarter, a 276% increase over first-quarter 2016 and the second highest quarter since GTM and the ESA began tracking energy storage in 2013, beat only by installation in the fourth quarter of last year.

Much of the growth in the first quarter can be attributed to “the shift from short-duration projects to medium- and long-duration projects in the utility-scale market, along with a surge of deployments geared to offset the Aliso Canyon natural gas leak,” said Ravi Manghani, GTM Research’s director of energy storage.

The Also methane gas leak jeopardized the flow of fuel for gas-fired generation, so the California Public Utilities Commission in May 2016 granted fast track approval for 104.5 MW of battery-based storage systems Southern California Edison and San Diego Gas & Electric’s service areas to offset the possible curtailment of gas-fired generation.

While the speed and scale of the Aliso Canyon storage deployments is impressive Manghani says the industry “shouldn’t get too comfortable” with that scenario because there are not that many 10+ megawatt-hour projects in the 2017 pipeline, indicating that the first quarter may be the largest quarter this year.

The completion of large storage projects is also reflected in the fact that 91% of all deployments in the first quarter were front of the meter projects. Front of the meter installations also grew by 591% on a year over year basis, boosted by large projects in California, as well as Arizona and Hawaii.

In Arizona, Tucson Electric Power signed a power purchase agreement for a low cost solar-plus-storage project that features a 100 MW solar array and a 30 MW, 120 MWh energy storage facility.

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Characterized by diverse geographic regions and climate zones, cities, towns and villages in Chile often are separated by difficult terrain and long distances, Sitting atop one of two colliding tectonic plates – the oceanic Nazca and continental South American – the Andean nation, as has come to be known worldwide, is also prone to cataclysmic earthquakes.

Given all this, Chileans are increasingly recognizing, aand taking advantage of, the prospective benefits held out by renewable microgrids, including those in which solar-plus-storage are core elements. Italy’s Enel Green Power numbers among the players participating in Chile’s emerging “green energy” revolution.

On May 31, the Rome-based multinational clean energy services company announced its Enel Green Power Chile subsidiary had commissioned “the world’s first 100% emissions-free ‘plug-and-play commercial-sized microgrid.” Relying on a combination of a 125kWp (kiowatt-peak) solar photovoltaic (PV) power generation and 580-kilowatt-hours (kWh) of lithium-ion battery (LiB) (132-kWh) and hydrogen energy storage (450-kWh), the all renewable microgrid is supplying part of the electricity needs of Enel’s Cerro Pabellón geothermal power plant in Chile’s northern Antofagasta region 24×7, management highlights in a news release.

More than 600 technicians work at Enel Green Power’s Cerro Pabellón geothermal plant in the are of Ollagüe in northern Chile’s Antofagasta region. The province of Antofagasta borders the 1,000 kilometer (625 mi) long Atacama Plateau, the driest non-polar desert in the world, the Sahara being no exception.

The Antofagasta region is also home to the vast bulk of Chile’s copper, which has long been the Andean nation’s primary export and source of foreign currency earnings. Sparsely populated, copper and other mining activities dominate the regional, as well as national, economy. Some mining companies active in the region have taken to tapping the region’s abundant solar energy resources to power their mining operations.

Enel Green Power’s Cerro Pabellón geothermal plant at a stretch could be considered mining – mining for clean energy. Tapping Antofagasta’s solar energy resources, and enhancing them with the addition of hydrogen and LiB energy storage capacity, adds to the company’s innovation and “green” energy credentials, as well as marking a world first.

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CARROLL, N.H. — Energy storage technology is still moving faster than state regulators and the markets can accommodate, speakers told the 70th Annual Symposium of the New England Conference of Public Utilities Commissioners (NECPUC) on Tuesday.

“Markets are moving at the pace of entrepreneurs, while states are moving at the pace of bureaucracy,” said Richard Fioravanti of energy consultancy Exponent.

The technology is changing so fast that CAISO recently had trouble qualifying a new lithium-ion battery storage project for California’s ancillary services market.

“You may think of some complicated reason why, but it was actually very simple,” said Jason Allen, vice president of operations and power for AltaGas Services U.S. The company’s 20-MW, 80-MWh facility in Pomona, Calif., holds 12,240 lithium-ion batteries. “We were ramping so fast they couldn’t” get an accurate data reading.

CAISO needs three data points to qualify a project during an ancillary services test: a starting point, one point on the ramp portion of the curve and an end-point.

“I can go from 20-MW charge and 20-MW discharge every 100 milliseconds, or 10 times a second,” said Allen. “It took [almost] two months working with them to get that simple issue worked out. And instead of the 10,000-MW/minute ramp rate, we actually detuned the system to 100 MW/minute and qualified for 36 MW [per minute], which is physically where we’re sitting right now in the market.”

Allen emphasized that his dealings with CAISO were not adversarial. “They have worked very closely with us to resolve the issues,” he said.

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Hybrid systems combining the complementary aspects of more than one technology could “change the energy storage landscape”, with 2.1GW predicted for deployment in less than 10 years, according to a report from Navigant Research.

“Hybrid advanced battery markets: Battery-battery, battery-capacitor, and other hybrid systems: Global market analysis and forecasts” says that by 2026, the installed capacity of such systems will be 2.1GW, an enormous leap from around 78.6MW today. Hybrid energy storage systems “have the potential to change the energy storage landscape and give customers better options to service their needs,” Navigant said.

Navigant defines hybrids as “a stationary ESS that integrates two or more energy storage technologies with complementary operating characteristics”. Most battery-based systems are either designed to offer short bursts of high power or suited to energy-intensive applications that consistently put out low power for longer durations. Using energy storage technologies in applications for which they are not the best fit can result in performance degradation and can have cost implications – it can also lead to safety issues around charging and discharging batteries.

Lithium-ion batteries, for instance, are commonly used in grid-scale storage to respond quickly to grid signals that there is a fluctuation in supply and demand, leading to deviations in grid frequency. These will put out high bursts of power for short times to keep the grid operating at as close to 50Hz (or 60Hz as required) as possible. Conversely, the same battery may not be suited for storing solar PV energy for several hours, perhaps for use at night, where something like a flow battery, capable of storing larger amounts of energy for longer durations may be better.

In a recent interview, the CEO of redT, a company that makes flow batteries (but prefers the term ‘flow machines’) Scott McGregor, told Energy-Storage.News that a theoretical hybrid energy storage system of lithium-ion batteries and vanadium redox flow could be optimal for delivering both high power and high energy functions within the same installation.

While the promise of lithium-flow hybrids sounds enticing, no significant projects along those lines have yet been built. However, recently announced hybrid systems include a flywheel-plus-battery project in the UK and a lead acid battery-ultracapacitor system in Ireland. On a slightly different tack, US engineering giant GE has launched hybrid gas turbine-plus-battery systems, some units of which have already been provided to a California investor-owned utility (IOU).   

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