PV is now producing more electricity than coal in the U.K. But don’t expect a storage boom to follow.

According to GTM Research’s Global Solar Demand Monitor, the U.K. has become the largest market for solar demand. But concerns over the eligibility for subsidies are forcing asset owners to delay adding storage to PV projects, said Jill Cainey, director of the Electricity Storage Network. 

The U.K. PV industry is largely supported through a Renewables Obligation Certificates (ROC) scheme that was designed before the advent of solar-plus-storage plant designs. 

PV asset owners wishing to add storage to their plants would have to reapply for ROC accreditation with their distribution network operator. Payments under the ROC scheme would then be suspended pending the outcome of the accreditation process. 

Even though any interim payments would still be awarded once the accreditation was granted, the temporary halt in cash flow “is something an investor would not be excited about,” Cainey said. 

This month, she attended a U.K. renewable energy trade show, Clean Energy Live, and “there were no solar farms deploying storage.” 

At the same time, the U.K. market for residential solar-plus-storage looks unlikely to take off in the near future because of unfavorable economics. 

Recent research by Delta Energy & Environment suggests the payback time for U.K. residential PV-plus-storage could be 16.9 years for a new system and 24.5 years for a retrofit, not taking subsidies into account.  

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We often hear that energy storage is a few years behind the solar industry. Comparing these industries’ respective trade shows helpfully illustrates this point.

Solar Power International drew 18,000 people to Las Vegas in September, with panels sprawling throughout the convention center and two massive expo floors. There were espresso bars, two-story display stands and plenty of lights, shiny things and after-parties at swanky Vegas nightclubs.

By contrast, the 2,000-person Energy Storage North America in San Diego last week felt quiet and provincial, closer to a hometown parade than a county fair. The expo had some familiar names from SPI, but focused more on fostering conversations between like-minded storage wonks than on wowing an audience with bells and whistles.

Many of the conversations at the conference dealt with how to put storage on track to where the solar industry is now. Most of the air time went to addressing policy and regulatory obstacles so that the existing storage technologies can get paid for the services they provide. There weren’t any earth-shaking revelations, but a steady march toward the boom that the industry and its observers have predicted.

Here are a few of the insights stumbled upon while wandering the halls.

Massachusetts storage companies are getting fired up

At the state level, California has long dominated the storage game, having passed the first statewide storage mandate in the U.S. back in 2013. Employment in the storage industry is correspondingly concentrated in California.

This summer, the Massachusetts legislature authorized the state’s Department of Energy Resources to decide if it thinks a target would make sense. That same department released a study last month saying that up to 1,766 megawatts of storage capacity would provide a net benefit to ratepayers, so chances are good that a target will become reality.

This, plus New York City’s new 100-megawatt storage target, creates the strong possibility of a high-growth market in New England. There’s already a cleantech hub around Boston, and companies based there will be well placed to nab new contracts. The opening of a new market there could create space for new companies to jump in as well.

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Amber Kinetics, the flywheel energy storage startup, has landed a project with Hawaiian Electric, a utility that’s looking for all kinds of distributed energy resources to make solar and wind an integral part of its grid.

It’s the first project outside of California for the Union City, Calif.-based company, albeit a small one — a single Gen2 Model 25 steel flywheel system at the Campbell generating station, one of the two big power plants that keep Oahu’s grid energized.

Hawaiian Electric will be testing the 25 kilowatt-hour unit to evaluate how it stands up against a long list of energy storage projects it has underway. These range from utility-scale batteries, to distributed projects, like Stem’s megawatt of behind-the-meter batteries in commercial buildings, or the grid-responsive water heaters being installed in homes across the island.

Amber Kinetics burst onto the scene late last year with a 20-megawatt, 80 megawatt-hour contract with Pacific Gas & Electric, but it’s been developing its technology for years now. That work has included testing in the Bay Area, as well as in Hawaii, where it’s been a partner of the state’s Energy Excelerator green tech incubator since 2013.

The startup’s main claim to fame is its multi-hour energy storage duration — a rarity for a technology better known for delivering huge bursts of power over short timeframes. That’s mainly because spinning heavy disks or cylinders can pack a lot of punch, but tend to lose long-term storage potential through friction.

We’ve seen a handful of utility-scale flywheel projects built, such as the Beacon Power 20-megawatt installation in upstate New York. But they’ve exclusively been used for fast-responding, short-duration grid services, like frequency regulation.

Amber Kinetics says it has surmounted the barriers to long-lasting kinetic energy storage, with a combination of better design, more homogeneous steel disks to reduce friction, and the latest super-efficient electric motors and power electronics. The units can “support unlimited cycling with zero capacity loss over a 20-year-plus service life,” according to the company.

That puts its technology into the running against electrochemical batteries like lithium-ion or metal-oxide flow batteries for a broader set of utility needs. In the case of its PG&E project, Amber Kinetics is expected to supply up to four hours of energy per day during times when the system is facing peak demand for electricity.

Hawaiian Electric hasn’t specified just how it plans to test its new flywheel, but it certainly has a need for energy storage to help it manage its growing share of solar and wind power. Nearly one in 10 homes on Oahu have solar panels, and large-scale wind farms are being built with batteries to help integrate their on-again, off-again energy into the grid.

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Research by a German team could aid the superconductor industry by improving capacitance by an order of magnitude compared to current approaches. The researchers identified the improvement when using a “hybrid mix” of potassium ferricyanide in aqueous media.

In a paper titled “High-Performance Hybrid Energy Storage with Potassium Ferricyanide Redox Electrolyte,” the team from the Leibniz Institute for New Materials (INM) in Saarbrücken also described how they overcame current leakage with an ion-exchange membrane.

The team, led by Professor Volker Presser of INM’s Energy Materials program division, found the hybrid medium had an energy capacity of 28.3 watt-hours per kilogram, or 11.4 watt-hours per liter.

This nears the 30-watt-hours-per-kilogram upper limit for current supercapacitor products and is “higher compared to the same cell operated in aqueous sodium sulfate,” said the team. 

The researchers also noted “excellent long-term stability” across 10,000 charge and discharge cycles. “This hybrid electrochemical energy storage system is believed to find a strong foothold in future advanced energy storage applications,” concluded the study’s authors. 

Lu Zhang, a scientist at Argonne National Laboratory in the U.S., said the redox electrolyte was a “key aspect” of the research. “This ferricyanide redox electrolyte can provide a higher capacity, [delivering] higher power out of the devices with this chemistry,” he said. 

“Another important finding is the ion-selective membrane. That is another key component to maintain the capacitance here, preventing the cell’s discharge, which would lead to the degradation of the capacitance,” said Zhang.

He said the research could be used to build supercapacitors that would last longer in a steady state without discharging: “You don’t want self-discharge happening. When you charge the capacitors, you want the energy holding there for as long as possible.” 

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Only two U.S. states, California and Massachusetts, have set targets for energy storage deployments. Now New York City has joined them.

The city government unveiled a storage goal of 100 megawatt-hours by 2020 last week, along with an expanded solar target of 1,000 megawatts by 2030. Storage, with its capacity to integrate variable wind and solar power sources into the grid, is expected to play a critical role in meeting the city’s plans to cut greenhouse gases by 80 percent by 2050.

Storage experts told GTM that this is the first time a city has set such a target.

The city’s target is not a legally binding requirement like California’s. It’s more of an aspirational target with policies designed to make the process easier. 

“With a city-based target, they are also directly responsible for building codes and siting regulations, deployment strategies and even local taxes — and the city can also take steps to adapt all these rules and regulations to accelerate deployment,” wrote Matt Roberts, executive director of the Energy Storage Association, in an email. “The city is able to marshal its forces toward this collective goal, and can more easily adjust the goal based on the observed value delivered in the future.”

The New York City target applies to the full spectrum of storage, including electrochemical and thermal technologies. City officials are targeting storage as a way to reduce demand charges, defer distribution system upgrades, pre-cool buildings and shift solar power consumption.

For all the potential use cases, energy storage is still a bit player in the city’s energy system. A major motivation for the storage target is to make permitting easier, said Daniel Zarrilli, senior director of climate policy and programs with the city.

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The U.S. energy storage market is in a period of transition.

Last year was a big one for storage, with Q4 2015 alone logging more total megawatts deployed than 2013 and 2014 combined. This growth drew increased attention from investors, regulators, consumers, and system operators. And in 2016, battery storage has expanded its foothold beyond its historically favorable markets, capitalizing on improved economics and a renewed focus on reliability. GTM Research has analyzed several key indicators of a transition for America’s storage market.

Front-of-the-meter deployment trends

The front-of-the-meter energy storage market logged another strong quarter in Q2 2016, recording 32 megawatts of new installations. This new capacity is down 10 percent from Q2 2015, but up over threefold from Q1 2016, continuing the trend from 2015 of deployments increasing toward the end of the calendar year.

Grid-scale energy storage is getting traction outside of its historically strong markets. New deployments in PJM are down in 2016 following the institution of an interim cap on RegD resources the frequency regulation market. For the first time since Q2 2014, PJM did not represent the majority of utility-scale deployments.

Front-of-the-meter policy trends

Policy developments dominated news in the front-of-the-meter market. Energy storage procurements in response to the Aliso Canyon gas leak in California could serve as a case study for energy storage as an expedited solution to capacity issues. SDG&E has signed an agreement with AES to install and commission 37.5 megawatts of Samsung batteries by January 2017. SCE has announced two 20-megawatt projects, one to be built by AltaGas with Greensmith batteries and one using Tesla batteries, along with a 2-megawatt project by Powin Energy and a 5-megawatt project from Western Grid. Successful deployment in the short timeframe required would be a tremendous success story for grid-scale batteries, and serve as further proof of the technology’s speed of installation and potential to enhance reliability.

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The government of Massachusetts released a study last Friday that lays out the costs and benefits of energy storage, setting the stage for a storage mandate that is yet to be determined.

The report concludes that 600 megawatts of storage capacity installed by 2025 would save the state’s ratepayers $800 million in system costs. Not only that, but if storage is properly located and market and policy barriers are removed, a deployment of 1,766 megawatts would optimize system benefits for ratepayers.

Plenty of researchers have modeled the value that storage and other distributed energy resources can provide for the grid. The State of Charge report, though, comes after Governor Charlie Baker signed an energy bill in August authorizing the Department of Energy Resources to set a storage target. That same department co-authored this report, marking one of the very few times when the authors of such research have the legal authority to enact their recommendations.

“These findings will be a driving force for establishing procurement goals in the state, and clearly demonstrate that the value of energy storage extends far ‘beyond the fence’ of any one system,” wrote Energy Storage Association Executive Director Matt Roberts in an email Friday.

Assuming the department follows through on its prerogative, Massachusetts will be only the third state to issue a mandate for energy storage, following California and Oregon. Since storage can provide readily available power during peak demand events, it’s useful to measure a target as a percentage of a state’s peak load. The 600-megawatt figure in the report would equate to about 5 percent of Massachusetts’ peak load, whereas Oregon’s target is 1 percent and California’s is 2 percent.

“In peak load percentage metrics, this is already a more aggressive target than the other two states,” said Ravi Manghani, energy storage director at GTM Research.

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The U.S. energy storage market is in a period of transition.

Last year was a big one for storage, with Q4 2015 alone logging more total megawatts deployed than 2013 and 2014 combined. This growth drew increased attention from investors, regulators, consumers, and system operators. And in 2016, battery storage has expanded its foothold beyond its historically favorable markets, capitalizing on improved economics and a renewed focus on reliability. GTM Research has analyzed several key indicators of a transition for America’s storage market.

Front-of-the-meter deployment trends

The front-of-the-meter energy storage market logged another strong quarter in Q2 2016, recording 32 megawatts of new installations. This new capacity is down 10 percent from Q2 2015, but up over threefold from Q1 2016, continuing the trend from 2015 of deployments increasing toward the end of the calendar year.

Grid-scale energy storage is getting traction outside of its historically strong markets. New deployments in PJM are down in 2016 following the institution of an interim cap on RegD resources the frequency regulation market. For the first time since Q2 2014, PJM did not represent the majority of utility-scale deployments.

Front-of-the-meter policy trends

Policy developments dominated news in the front-of-the-meter market. Energy storage procurements in response to the Aliso Canyon gas leak in California could serve as a case study for energy storage as an expedited solution to capacity issues. SDG&E has signed an agreement with AES to install and commission 37.5 megawatts of Samsung batteries by January 2017. SCE has announced two 20-megawatt projects, one to be built by AltaGas with Greensmith batteries and one using Tesla batteries, along with a 2-megawatt project by Powin Energy and a 5-megawatt project from Western Grid. Successful deployment in the short timeframe required would be a tremendous success story for grid-scale batteries, and serve as further proof of the technology’s speed of installation and potential to enhance reliability.

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We’ve said it here, and it’s been said elsewhere: lithium-ion batteries just don’t pencil out for backup power. The incumbent technologies, like diesel generators and lead-acid batteries, have a big lead in affordability for essentially the same service.

It was surprising, then, to hear Greg Smith, the senior technical trainer for battery-maker Sonnen, tell a crowd at Solar Power International that “the overwhelming portion of the systems we sell is for backup.”

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The Global Energy Storage Forecast, 2016-24, published by Bloomberg New Energy Finance (BNEF), predicts the Asia Pacific region will host a majority of the 45 gigawatts and 81.3 gigawatt-hours of non pumped-hydro storage due to be installed worldwide by 2024. 

By then, the Asia-Pacific region will account for 53 percent of the world’s total capacity in megawatts. Three Asian countries — Japan, India and China — will be among the world’s top five markets for energy storage.

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