Grid integration of renewable energies, increased efficiency and durability of lithium-ion batteries, and the step towards megawatt output: The ees Award 2017 reflects the current developments in the industry. Finalists for the prestigious award have been selected from a wide range of international submissions. The winners will be announced at ees Europe, the continent’s largest and most visited exhibition for batteries and energy storage systems, at the Innovation and Application Forum on 31 May, 2017. The exhibition takes place parallel to Intersolar Europe, the world’s largest exhibition for the solar industry and its partners, from 31 May to 2June in Munich.

Over the last few years, the energy storage industry has boomed. Systems are becoming increasingly affordable – for example, lithium-ion storage systems were 15% cheaper in the second half of 2016 than the start of 2015 – making it increasingly attractive to invest in this technology. The development is being driven by numerous innovations which make batteries more powerful and more reliable. The ees Award has been honoring pioneering developments in the industry for four years.

Submission trends

The industry is clearly dominated by the topics of efficiency and durability, which is reflected in the submissions for the 2017 ees Award. The vast majority of projects submitted were in the area of lithium-ion technology, with a marked increase in high-voltage storage systems. Progress has been made in terms of energy density, capacity and lifespan. Easy-to-install modular storage systems are another hot topic. Self-configuring battery systems make design and installation easier and minimize potential sources of defect. And to boost functionality, there is a trend towards standardizing interfaces and data logs. Quality and safety also play an important role amongst this year’s submissions. The aim is to develop systems which can be used safely for longer, while minimizing operating expenses. Large-scale storage systems in the megawatt range are gaining a foothold in the market, thanks to the decreasing cost of lithium-ion batteries. These systems support the grid by providing balancing power and stabilizing frequency and voltage, and are used as an emergency power supply or mini-grids in combination with PV and wind energy installations. Lead battery systems are also being optimized, and are frequently used in off-grid applications. Here too, there is a trend towards modularity and reducing installation and operating costs. Standardized PV battery systems which are compatible with mini-grids can be scaled to any size, and thus make it possible to supply self-controlled and self-learning power in remote areas.

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It’s the stuff of an action-hero movie: An accident threatens an unsuspecting metropolis. Electricity supplies face disruptions and millions are at risk of being without electricity as blackouts roll across the city. Faced with the prospect of escalating chaos, officials gather on the steps of government buildings and implore, “Who can help us?”

But let’s leave that cliffhanger for a moment, knowing that reality was not quite so—shall we say—Hollywood.

Even so, this movie-quality crisis is based in fact and has energy storage as its action hero. The increasingly mainstream zero-emission technology helped ease a real-life crisis that had all the makings of a major catastrophe.

Official records say that on 23 October 2015, a significant natural gas leak in well SS25 was detected at the Aliso Canyon natural gas storage facility in the San Fernando Valley north of Los Angeles. Repeated attempts by Southern California Gas Co., the owner, to “kill”—plug up—the well and stop the leak failed.

SoCalGas relies on Aliso Canyon to provide gas for core customers—homes and small businesses—as well as non-core customers, including hospitals, local governments, oil refineries, and 17 natural gas-fired power plants with a combined generating capacity of nearly 10,000 megawatts.

As part of a multi-part response to the crisis, the California Public Utilities Commission in May 2016 fast-tracked approval of 104.5 MW of battery-based energy storage systems within the service areas of Southern California Edison (SCE) and San Diego Gas & Electric (SCD&E).

Those utilities, along with the Los Angeles Department of Water and Power—the nation’s largest municipal utility—provide gas and electric service to most of southern California. By the end of February 2017, seven of eight fast-tracked Aliso Canyon–related energy storage projects were online, helping the region’s energy grid regain stability.

The significance of the Aliso Canyon energy storage deployment is “hard to overstate,” says Alex Morris, director of policy and regulatory affairs for the California Energy Storage Alliance, an advocacy group.

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Have you heard the line recently that grid-based battery storage is “coming”, but is not quite “commercial”, but might be in a few years time, or even a decade or two?

It’s a common misconception. But if you wondered about the overwhelming response to the recent tenders by South Australia and Victoria for the country’s largest battery storage installations, here’s why: The technology is already in the money.

That, at least, is the estimate of Bloomberg New Energy Finance analyst Kobad Bhavnagri, who says that battery storage is not just in the money, it is a long way into the money in states like South Australia, already with a high level of wind and solar and volatile wholesale electricity prices.

“We’ve seen the price of battery packs as fallen by 75 per cent by 2010, and our calculations show that will fall by a further 75 per cent by 2030,” due to technology innovation and manufacturing scale, Bhavnagri said.

That means that large-scale battery storage is already viable in large parts of Australia. In South Australia, it is offering internal rates of return of around 30 per cent (even without new market rules that will further encourage them), and in Queensland they are also profitable due to that state’s price volatility. NSW and Victoria will follow soon enough.

“That is a  great story for integrating renewables,” Bhavnagri said. (And we should also point that this value stack for storage does not include network benefits, where battery storage is already seen to reduce cost of upgrades of poles and wires by around 30 per cent).

So, what does this mean for the grid? The CSIRO and the Energy Networks Australia gave some insight into this in their report last week, in which they outlined their pathway to a zero emissions grid based around solar, wind and storage, and why it would be much cheaper, cleaner, smarter and more reliable than the current iteration.

AGL Energy gave its own version of the future this week in a presentation to a Macquarie Group conference. As we reported earlier, the company once known as Australian Gas Light no longer sees gas as a transition fuel.

AGL says the economics of gas-fired generation don’t stack up, because wind and solar and storage are cheaper, and major gas producer Santos this week gave us an insight into why gas has little credibility on the environment front.

In his presentation, AGL chief financial officer Brett Redman provided this graph illustrating what has been presume to happen on the left – renewables with gas filling in the gaps – and what will happen with storage.

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The notice for next week’s Federal Energy Regulatory Commission (FERC) conference on the intersection of wholesale energy markets with state energy policies says that there is an “open question of how the competitive wholesale markets, particularly in states or regions that restructured their retail electricity service, can select resources of interest to state policy makers while preserving the benefits of regional markets.”

This is an intriguing understatement for a conference that provides at least a starting point for the hard discussion the energy sector must have about the need to catch wholesale market rules up with the reality of this country’s changing power generation mix.

How did we get here?

The states of wholesale energy market design and FERC, the federal agency that regulates that design, are in flux. Regional wholesale energy markets, intended to increase competition in the sale of energy and related services like capacity and reserves, were designed around the marginal cost of predictably dispatchable central station power plants with variable fuel costs.

During the several decades that most power plants exhibited these similar operating characteristics and natural gas prices were at least meaningful, coal and nuclear power plants proved successful in clearing markets to provide competitively priced energy. The last decade’s sustained plunge in natural gas prices, however, along with declining demand due to energy efficiency and an exponential increase in zero marginal cost wind and solar power plants coming online, and, to a lesser extent, the cost of environmental compliance for outdated fossil-fueled power plants, has dramatically altered the equation.

Coal and nuclear power plants that reliably cleared the markets have found themselves failing to recover costs, while natural gas rules the margin and wind and solar power and customers’ demand response contribute to lowering energy prices. The relatively rapid change has led to countless specific changes by regional market operators (buyer side mitigation battles, anyone?) trying to manage the transition as well as attempts by states like Maryland, New Jersey, and more recently, New York and Illinois, home to some of these failing power plants, to enact policies that protect their resources – with varying degrees of justified reliability and cost concerns.

Stepping back, it is fair to say that an increasingly severe disconnect exists between the services wholesale markets are designed to provide and the grid services necessary to reliably and cost-effectively support an electric grid increasingly powered by renewable energy resources. Determining and then monetizing the value of grid services necessary to support a renewables-dominated electric grid is critical to ensuring cost-effective reliability in our new world. (FERC and regional grid operators are by no means oblivious to this disconnect – next week’s conference is exhibit A, with B and C being efforts by regions like New England and PJM to get at the bigger market design issues, at least to the extent politically realistic.)

At the same time, pre- and post- presidential election events have FERC down to two commissioners, one short of quorum from a potential full slate of five. Acting Chairman LaFleur and Commissioner Honorable obviously recognize the urgency of the market reform need, but cannot act until at least one more Commissioner is appointed and confirmed.

It is at this crossroads from which the next stage of market reform must take form.  

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MILWAUKEE, May 4, 2017 /PRNewswire/ — EnSync, Inc. (NYSE MKT: ESNC), dba EnSync Energy Systems, a leading developer of innovative distributed energy resource (DER) systems and internet of energy (IOE) control platforms for the utility, commercial, industrial and multi-tenant building markets, today announces the sale of a solar-plus-storage power purchase agreement (PPA) project to a leading U.S. infrastructure investor.

The system will be comprised of a suite of EnSync Energy’s DER technologies, including two EnSync SuperModule™ systems with Matrix™ Energy Management and EnSync lithium-ion batteries, as well as the DER Flex™ internet of energy (IOE) control platform.  The project also includes approximately 400kW of carport-mounted photovoltaics, and will provide electricity to dedicated loads at the Oceanic Time Warner head-end operations center in Kailua-Kona, HI.

“We have a great business model and proven installations demonstrating that solar-plus-storage PPAs are a very effective way to achieve lower electricity prices, sustainable power generation, resiliency and a good return on investment,” said Brad Hansen, CEO and President of EnSync Energy Systems.  “We’re delighted to have another significant success in Hawaii.  Our long term commitment and leadership in the state continues to yield great results for the Company.”

The EnSync Supermodule™ is a Distributed Energy Resource “in-a-box”, with all critical modules in place that enable integration and control of the renewable energy generation, energy storage and grid, such that the most economic electricity available can be used by the load at any given time.  Additionally, the DER Flex™ IOE enables complete integration to the grid network, allowing future participation in utility and ISO grid services, including applications such as supply response on demand.

The EnSync Distributed Energy Resource (DER) system will serve Oceanic Time Warner’s head-end facility on the Island of Hawaii, which is the critical operating facility that receives television signals for processing and distribution over the island’s cable television system.

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The San Diego County Water Authority announced it will seek detailed proposals for a potential energy storage facility at the San Vicente Reservoir that could total up to 500 MW. The official RFP will go out this summer.

The request for proposals follows a January request for letters of intent to measure interest in the facility. In response, the Water Authority received 18 responses from qualified parties, including five full-service entities that would finance, design, permit, built and operate the potential project and secure an off-taker for the produced energy. The other respondents included two developers, five off-takers, and six other parties interested in constructing the project, providing equipment for the project or serving as a consultant for engineering, procurement, and construction services.

“We wanted to find out if there really is a broad desire among potential stakeholders to see a project like this in our region, and now we know there is,” said Mark Muir, chair of the Water Authority’s Board of Directors. “We’re now going to gather more details about how it could come together for the benefit of ratepayers.”

The Water Authority intends the project to ease pressure on the electric grid, keep electric service reliable and keep water rates from rising by providing a new source of revenue.

Discussions with entities that responded to the RFP confirmed the authority’s findings from feasibility studies that began in late 2013. Namely, the project would help stabilize the grid, the project size is appropriate and infrastructure to support the project already exists.

The project would include an interconnection and pumping system between the reservoir and a new, smaller reservoir uphill that would be used during off-peak energy use periods to pump water uphill to the upper reservoir and create a bank of stored hydroelectric energy. That energy would be released to the lower reservoir as needed.

The Water Authority already operates a similar energy storage facility at Lake Hodges with a capacity of 40 MW. 

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The energy storage sector is expanding rapidly as growth in independentrenewables flatlines with UK battery capacity poised to grow up to 100 times by 2020, a new report suggests.

On average, 275 independent renewable projects have completed each quarter since 2013. However, in the wake of deep subsidy cuts, just 38 were completed from October to December 2016 and from January to March 2017 the figure fell to 21, according to renewables firm SmartestEnergy’s latest energy entrepreneurs report.

As the market remains challenging for renewables, energy entrepreneurs are beginning to move outside the traditional supply sector towards energy storage, which will allow the UK’s energy system to accommodate growing amounts of renewables, helping to balance supply and demand.

“Independent developers have won four fifths of battery contracts in Capacity Market auctions, which ensure there is enough electricity to meet peak winter demand. They secured 407 megawatts while just 105 megawatts went to projects from Big Six utilities, and the majority was secured by independents with renewable projects. Independents have also won more than half the battery contracts to provide Enhanced Frequency Response (EFR) to stabilise the grid, 110 megawatts out of 201 megawatts,” the report said.

In 2016 there were just 20 megawatts of commercial batteries in operation, but 31 projects have now won long-term contracts in the capacity and EFR markets to provide 578 megawatts of capacity in 2020.

All together, 153 projects with a combined capacity of 2.3 gigawatts have announced plans for deployment over the next four years, which would cause UK battery capacity increase by more than 100 times.

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Batteries that have powered electric cars around the UK will get a second life providing energy storage for households, with the launch this week of a British-made home battery to rival the one made by Elon Musk’s Tesla.

The cells will be made by the Japanese car-maker Nissan in Sunderland, where its popular Leaf electric car is built, and sold in partnership with the US power firm Eaton. Buyers will be able to choose cheaper, used batteries that are no longer fit for electric car use, or pricier new ones.

They are believed to be the first British-made household batteries pitched to the embryonic UK home storage market.

The batteries inside the Tesla Powerwall were previously made in Japan by Panasonic, but since January have been produced at its vast Gigafactory in California. Sonnen, a German storage company, builds its European and Australian home batteries in Wildpoldsried, Germany.

With falling costs, home storage is seen as increasingly attractive in the UK, particularly to early adopters and the 850,000 homes with solar panels.

Solar owners can make the electricity they generate more valuable by storing it in the battery and using it later instead of exporting it to the grid – Eaton and Nissanestimate such customers will be about £43 better off each month.

Batteries also make it easier for people to take advantage of “time of day” energy deals, which charge consumers less if they avoid periods when energy demand peaks, for example at 4-7pm on weekdays. Such tariffs are expected to proliferate as every UK home is fitted with a smart meter by the end of 2020.

Nissan has partnered with Eaton, a US power management company with revenues of $20bn (£15.5bn), to sell the XStorage Home systems, which are about the size of a conventional boiler.

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Since the day Tesla was founded, executives saw stationary storage as a compliment to the electric car business.

That was Martin Eberhard’s plan when he co-founded the company and envisioned the Tesla Energy Group. Years later, after launching the Powerwall, CEO Elon Musk said the storage business could soon eclipse automobiles. Today, storage is an integral part of Tesla’s package of offerings for consumers, and its development plans for utilities. 

In 2009, Mateo Jaramillo was hired to execute Tesla’s storage strategy. Well, eventually.

First, he was responsible for developing the company’s powertrain. Over time, he became more heavily involved in stationary storage — eventually building Tesla’s in-house storage development arm and the team that designed the Powerwall and Powerpack. He drew on his years of experience at Gaia Power Technologies, where he worked on some of the earliest behind-the-meter battery systems in New York.

Last December, Jaramillo left Tesla to focus on his next career move in storage. The LinkedIn description of his new job job reads: “The Next Thing.”

This week, we caught up with Jaramillo to talk about what that “next thing” might be. We talked about the history of behind-the-meter storage, the evolution of Tesla’s approach to the market, and where storage business models and applications are headed. 

Thanks to our launch sponsor, AES Energy Storage. The grid is changing. Fast. And AES Energy Storage is helping utilities harness the power of battery-based energy storage to make the electric power system cleaner, more flexible, and more reliable. Find out more.

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