Duke Energy announced plans to install North Carolina’s two largest battery storage systems — which stands as a US$30 million investment as part of Duke Energy’s Western Carolinas Modernisation Plan.

Robert Sipes, vice president of Western Carolinas Modernisation for Duke Energy, said: “Duke Energy has experience with many battery storage projects around the nation. Western North Carolina is an ideal spot to use this technology to serve remote areas, or where extra resources are needed to help the existing energy infrastructure.”

The two sites are just the first part of a larger plan Duke Energy has to spur energy storage in the region.

A 9MW lithium-ion battery system will be developed in the city of Asheville and placed at a Duke Energy substation. The battery will primarily be used to help the electric system operate more efficiently by providing energy support to the electric system, including frequency regulation and other grid support services.   

The other energy storage system will be a 4MW lithium-ion battery system that will help improve electric reliability in the town of Hot Springs, located in Madison County.

Further details on the projects will be filed with the North Carolina Utilities Commission in early 2018. Both projects are expected to be online in 2019.

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New York City is in the trenches when it comes to employing innovative energy technologies, which it hopes will help meet its goal of reducing greenhouse gas emissions by 75% by 2050. How so? By installing 100 megawatt/hours of energy storage, which may also allow the city’s consumers to avoid buying dirtier power — something that could save electricity customers there millions each year, a new study says.

Balancing the electricity load is a difficult job. Storage devices, if they can be shown to work at commercial scale, would be a huge boon for utilities that are trying to do everything from advance renewable power to cut electricity use during peak demand. Today, storage adds value to power systems because it can create capacity. And that has the potential to allow utilities to defer investment in expensive infrastructure and carbon-intensive power plants.

Power producers are infatuated with energy storage, realizing that it could be a game-changer. But they are readily acknowledging that technical and financial barriers exist and that overcoming them is paramount if the devices are to reach their potential. An application could be anything from shaving peak load to storing and injecting wind and solar electrons onto the grid.

“As the (New York) state moves forward to meet its clean energy goals of 50 percent renewable energy by 2030 and an 80 percent reduction in greenhouse gas emissions by 2050, there are increasing questions about how we can best ensure the reliability of the electricity grid while reducing our reliance on fossil-fuel generation,” New York Battery and Energy Storage Technology Consortium (NY-BEST) Willam Acker said.

“This study illustrates that replacing these older peaking plants with energy storage presents a cost-effective strategy for reducing harmful air emissions, protecting public health and maintaining grid reliability,” he added. New York City set a goal in September 2016 to install 100 megawatt/hours of energy storage by 2020, along with 1,000 megawatts of solar capacity by 2030.

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Net metering was a key factor in driving the residential solar market to where it is today, but its days are likely numbered across the U.S.  Utilities nationwide are having success at convincing state regulators that they shouldn’t have to credit homeowners for the surplus power they export to the grid at the same rate they’re charged when they consume power from it, which makes sense now that solar power systems are on around 1 million homes. Hawaii, the state with the most rooftop solar per household, has long paid consumers less than the retail rate for electricity, and California recently followed suit.

But when utilities choose to pay less than the retail rate for rooftop-generated solar electricity, they give homeowners an incentive to save their short-term surplus and use it later, performing arbitrage on the difference between the two rates. To use solar energy at a later time (for example, at night) homeowners need energy storage systems. Providing those could be the next growth driver for rooftop solar companies. 

Solar sales could get bigger

Today, most solar installations consist of  solar panels, an inverter, and a connection to the homeowners’ meter. At an average cost of $3 per watt, a 6 kW solar system costs about $18,000. If energy storage can be made economical for the homeowner, it adds another component to those installation, giving the companies a new product, and a new stream of revenue. 

Depending on the size of the energy storage unit, that added revenue could be significant. A single 14 kWh Tesla (NASDAQ:TSLA) Powerwall costs at least $7,000 to install, and some homeowners may want two or more to increase their energy flexibility. Selling and financing those energy storage systems could be a big business for installers, potentially doubling the revenue opportunity of each solar sale. 

Installers have more to gain from energy storage

The big difference between solar panels and energy storage for installers is the ongoing operation. Solar panels produce electricity every day, but there’s no ongoing maintenance or controls that can add value to a system in the long term. By contrast, someone needs to decide when energy storage systems will be charged and discharged on an ongoing basis, which will be a big business. 

Energy storage business models aren’t set in stone yet, but look for companies to take a percentage of the cost savings homeowners accrue as a fee for controlling the system. This could be an ongoing source of revenue for companies that can build scale in this space.

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A group of Drexel University researchers have created a fabric-like material electrode that could help make energy storage devices — batteries and supercapacitors — faster and less susceptible to leaks or disastrous meltdowns. Their design for a new supercapacitor, which looks something like a furry sponge infused with gelatin, offers a unique alternative to the flammable electrolyte solution that is a common component in these devices.

The electrolyte fluid inside both batteries and supercapacitors can be corrosive or toxic and is almost always flammable. To keep up with our advancing mobile technology, energy storage devices have been subject to material shrinking in the design process, which has left them vulnerable to short circuiting — as in recent cases with Samsung’s Galaxy Note devices — which, when compounded with the presence of a flammable electrolyte liquid, can create an explosive situation.

So instead of a flammable electrolyte solution, the device designed by Vibha Kalra, PhD, a professor in Drexel’s College of Engineering, and her team, used a thick ion-rich gel electrolyte absorbed in a freestanding mat of porous carbon nanofibers to produce a liquid-free device. The group, which included Kalra’s doctoral assistant Sila Simotwo and Temple researchers Stephanie L.Wunder, PhD, and Parameswara Chinnam, PhD, recently published its new design for a “solvent-free solid-state supercapacitor” in the American Chemical Society journal Applied Materials and Interfaces.

“We have completely eliminated the component that can catch fire in these devices,” Kalra said. “And, in doing so, we have also created an electrode that could enable energy storage devices to become lighter and better.”

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While lithium-ion is rapidly racing ahead to become the “de facto grid storage solution” and is the most popular technology choice by far, vendors of other types of batteries are also targeting the market, with varying degrees of success.

US firm Navigant Research published ‘Navigant Research Leaderboard: Non-lithium ion batteries for grid storage’,  earlier this month, examining the technologies, business models and strategies for commercialisation and larger scale production of energy storage batteries that sit outside the many different sub-chemistries making up the lithium battery market ecosystem.

Lithium remains by far the most popular technology in energy storage. A recent edition of GTM Research and the Energy Storage Association’s jointly-published US Energy Storage Monitor, which gives quarterly updates on deployment figures, notable projects, market design and policies, found 94.2% of energy storage systems installed in Q2 2017 in the US used lithium batteries. Around 5% of the remainder were flow battery projects and a further 0.5% used lead acid.

While that percentage was in fact the first time since 2015 that lithium-ion battery systems had been found by GTM to have less than 95% market share, the lead looks all but unassailable. Indeed, even in longer duration applications of up to four or five hours, as one expert from IHS Market recently told Energy-Storage.News, lithium batteries are starting to have fallen enough in price to make sense.

According to Navigant, the speed at which costs of production fall and the presence of reputable, renowned vendors in the lithium battery space are its key advantages. However, as the ‘Leaderboard’ report shows, there are numerous companies making other types of battery energy storage that have reached commercialisation of their technologies and are already deploying them in the field, although still at the pilot stage in some cases. 

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Early this month, Generate Capital, a sustainable infrastructure finance company, and Sharp Electronics Corporation’s Energy Systems and Services Group announced the commencement of a six-site solar plus storage project at the Santa Rita Union School District (SRUSD) in Salinas, California. The project will include more than a megawatt (MW) of solar arrays, combined with 1.2 megawatt-hours (MWh) of Sharp’s SmartStorage on-site energy storage.

This initiative will be supported through the state’s reinvigorated Self-Generation Incentive Program, which offers significant incentives to bring more storage to the California power grid. The SRUSD will be able to cut energy costs (during some months, as much as 70-80% of the district’s electricity needs will be met by the systems). The district will also significantly reduce its expensive hourly utility demand charges (a dollars-per-kilowatt fee based on one’s highest demand during the month that can easily contribute to 30-40% of the total bill).

This project is part of a growing trend as the U.S. market has recently seen a significant uptick in the addition of on-site energy storage. GTM research reportsthat Q2 2017 saw 443 commercial and residential storage projects installed, totaling 32 MW. A large portion of these recent projects emanated from Hawaii and California. Solar and storage hybrids are coming on strong and will likely soon become commonplace, so from that perspective, the SRUSD project is not especially newsworthy.

What is newsworthy is the fact that the project was designed not only to save money, but also to provide critical backup power to the schools in the event of power outages. The project can help the SRUSD ride through brownouts or short-term outages, as well as longer-duration events. And in the aftermath of the recent devastation in Florida and Texas, the importance of backup power has increasingly come into focus.

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RIVERSIDE, Calif., Sept. 19, 2017 /PRNewswire/ — Sparked by strong demand for the groundbreaking energy storage system the company launched last year, SolarMax Technology has introduced a new model that more than doubles the amount of power homeowners can access when the grid goes down.  The 10kWh FLEX™ Energy Storage System, which combines two batteries with an inverter, targets the U.S. residential housing market.

Unlike many battery back-up systems, the FLEX™ requires no additional components or labor assembly by the customer. The fully integrated, all-in-one design saves consumers thousands compared to existing “ala carte” solutions that require the purchase of separate component parts in order to achieve comparable functionality.   

The lithium-ion powered batteries pack plenty of electricity when fully charged. When coupled with solar, the FLEX™ system can power a refrigerator, flat screen TV, laptop computer and five 7-watt LED lights for days after an outage – while still having enough power to keep a life-saving oxygen machine running for multiple hours. 

SolarMax will continue focusing its marketing efforts on existing solar customers, homeowners considering the value proposition of converting to solar, and even non-solar customers who simply want a reliable source of power when blackouts occur.

“If you’re a homeowner, the most important – and, often, the only thing – you’re concerned about in a black-out is being able to immediately switch over to a reliable source of back-up power,” said SolarMax CEO David Hsu.  “That’s the profile of the FLEX™ customer.  We designed and engineered the solution to offer a very strong value proposition.”

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On a paved expanse next to an electrical substation in Escondido, 30 miles north of downtown San Diego, sits a row of huge silver boxes. The site resembles a barracks, but instead of soldiers, the 24 containers house racks of battery packs.

This is the largest lithium-ion battery in the world, according to its developers. When the local grid needs more power, these batteries deliver, almost instantaneously. They can discharge up to 30 megawatts – roughly equivalent to powering 20,000 homes – and can sustain that level for up to four hours.

AES Energy Storage built the system in less than six months for utility San Diego Gas & Electric (SDG&E) in response to a four-month blowout at southern California’s Aliso Canyon natural gas storage facility. The rupture in October 2015 leaked more gas into the atmosphere than any other spill in US history.

After the leak was finally plugged in February 2016, utilities needed a fast-response energy source to deploy quickly in the densely populated areas around Los Angeles and San Diego. They wanted to prevent blackouts during periods of high demand, especially when customers crank up the air-conditioning on hot summer days.

Traditional grid solutions didn’t make sense. Gas peaker plants – which can be turned on quickly to meet demand – can take years to gain permission and be built, and they burn fossil fuels. You can’t drop a hydroelectric dam in the middle of a city. Solar power doesn’t help much in the evening, when summer demand is highest.

Instead, utilities Southern California Edison and SDG&E chose something relatively new: grid-scale batteries. What followed was the Escondido battery plus several others totalling about 100MW. The project became a major test case for the grid storage industry’s ability to make the grid more efficient and clean.

“To go from something that we thought of as kind of the future technology to, all of a sudden, it coming to the rescue so quickly – yeah, I think that’s a huge success story,” said John Zahurancik, president of AES Energy Storage.

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California is a leader in both renewable energy resources and energy storage. The state has one of the highest renewable portfolio standards in the U.S., mandating that 50% of all electric power be sourced from renewable resources by 2030, and the state has the first and some of the most robust incentives for energy storage.

AB 2514 requires the state’s three investor owned utilities to procure 1.3 GW of energy storage by 2020, and AB 2868 requires each IOU to deploy an additional 166 MW of behind-the-meter and/or distribution tied storage.

The IOUs are already well on their way to meet their goals. Southern California Edison has 400 MW of storage in its portfolio toward its 582 MW target. But installing energy storage is one thing, using it to meet other goals is another.

California is a restructured state, so utilities there generally do not own or build power plants. Nor do utilities control the dispatch of those plants. That is the job of the California ISO.

Soaking up solar power during the day and dispatching it in the evening is often cited as a renewable-enabling use for energy storage, but in practice the renewable-enabling potential of storage is often not so simple.

SCE, for instance, does not necessarily make decisions to charge batteries when solar power output is abundant and to discharge them when solar power begins to wane. But the utility still owns some generation assets and is responsible for how it bids those assets into CAISO’s real-time and day-ahead energy markets.

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The award of the contract for the world-record tariff for Dubai’s first concentrated solar power (CSP) project with storage could signal a seminal moment in the region’s shift towards renewable energy.

The UAE is leading the Gulf’s drive to turn talk about clean energy into action, and progress has been swift. Dubai and Abu Dhabi have both achieved world-record tariffs for utility-scale photovoltaic (PV) plants in the past couple of years, and the 7.3 $cents a kilowatt hour ($c/kWh) tariff achieved for the $3.8bn fourth phase of Dubai’s Mohammed bin Rashid (MBR) solar park has now set a world record for unsubsidised CSP solar production. More importantly, it represents the first time that utility-scale solar with storage has converged with natural gas-fired power plants. It is estimated that, including gas import costs, the total cost of producing power from gas-fired power plants in Dubai is somewhere in the 8 $c/kWh region.

While much of the push for solar energy across the region has been driven by the dramatic fall in costs for PV solar systems in recent years, the peaking nature of PV has meant it can only be used in tandem with conventional fossil-fuelled plants due to its inability to produce 24-hour power. CSP is able to circumvent this by enabling the storage of energy generated during sunlight hours to be dispatched at night.

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