Renewable energy is, undeniably, on the rise: solar and wind farms are popping up in the U.S., Europe, China, and Australia, while many companies are planning to source 100 percent of their energy from renewables. Side-by-side with this growing interest in clean energy are equally increasing energy storage needs. According to Spencer Hanes, a business development managing director at the North Carolina-based utility provider Duke Energy, batteries—like Tesla’s Powerwall and Powerpack—are going to take over the U.S. electric grid in five years.

“There’s going to be a lot of excitement around batteries in the next five years. And I would say that the country will get blanketed with projects,” Hanes said on Thursday, speaking as part of a panel at Solar Power Midwest in Chicago, according to Forbes.

Solar and wind farms generate energy at peak periods, when the sun is out and the winds are strong, but these don’t always match the needs of the grid. To remedy this, solar and wind farms, and even utilities, are turning to energy storage batteries. Tesla has a number of projects like this in Australia, while Google parent company Alphabet is working on a similar project in Malta.

CLEANER AND CHEAPER

Aside from batteries in larger energy farms, batteries are also becoming more popular domestically. Soon, more houses are going to be equipped with home batteries, like the Powerwall and Ikea’s home battery packs, as a reaction to the shift to renewables—and because they bring down energy costs. In the U.S., home developers in a number of state, which include New York and California, are making batteries part of their houses. “With the way that the cost curves are coming down it’s a big opportunity for all of us to deliver what customers want,” Hanes added.

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Indian state-owned company Energy Efficiency Services Limited (EESL) has invested $12m in the 28MW Basin 1 and 2 battery storage project in the Canadian province of Ontario.

EESL has partnered with UK advisor EnergyPro to form EESL EnergyPro Assets Limited (EPAL) for the project. The JV has invested $12m in the scheme.

The 28MW/14 MWh project will provide services to the Independent Energy Systems Operator that oversees and manages the power grid of the province of Ontario, and is interconnected to Toronto Hydro, the largest municipal electricity distribution company in Canada.

“We are excited to be working with our joint venture partner EESL and Leclanché on this significant utility scale energy storage project,” said EnergyPro managing partner Steven Fawkes.

“We see it as a first step to deploying energy storage solutions at a range of scales, something that will be essential to the energy transition in all economies.”

EPAL chairman Saurabh Kumar added: “It has been our constant endeavour to make future-ready technology solutions accessible. We are confident that this partnership will help bring a new era of clean energy solutions for the world.”

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Energy storage is hot, but some new entrants into storage struggle financially. However companies, like CALMAC and Ice Energy that use cooled liquid storage, say their profits are robust.

Cooled liquid storage uses low-priced nighttime electricity to freeze or cool a liquid and then uses the chilled liquid to help offset electric air conditioning loads when power prices peak during the day. Even before the announced merger, CALMAC was working with Trane to integrate its ice storage tanks with Trane commercial HVAC systems to take pressure off of the energy grid.

CALMAC says its thermal storage systems reduce energy usage by roughly 35% by decreasing need for carbon-emitting peaking power plants. Its business model targeted building owners, wooing customers by simply cutting their electricity bills, and impacting how high demand charges from peaking air conditioner use can be controlled.

“We made the decision to join Trane because of our long tenure and history with Trane’s people, application expertise and system design,” CALMAC President Mark MacCracken, said in a statement.

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The Department of Business, Energy and Industrial Strategy (BEIS) has refused to provide any clarity over when a decision on the potential derating of energy storage assets within the capacity market (CM) will be made despite a senior policy advisor stating the judgement is “imminent”.

In July BEIS proposed significant changes to how their generation classes are de-rated within the CM, suggesting that the majority of storage assets could lose their current 96% de-rating status in place of a mechanism designed to reflect the discharge duration of assets in the instance of a stress event.

With the exception of a methodology update in September, no further notices have been issued. Since this time, storage developers have entered their projects into pre-qualification for the next CM auctions scheduled for January/February 2018, with no knowledge of whether their applications will be affected by the rule change.

Speaking at Tuesday’s Solar Trade Association (STA) Market Access and Systems Integration conference, Alexander Berland told Clean Energy News the decision would soon be forthcoming.

“A publication is imminent; we are expecting a decision on that to be very soon. We do want to give clarity as soon as we possibly can as important decisions on investment are relying on that,” said the senior advisor for smart energy at BEIS.

He added that this information had come from the government’s security of supply team who govern the CM.

When asked to elaborate today on Berland’s comments, BEIS refused to clarify when this “imminent” publication would be issued, adding only that the department “will be publishing in due course”. The department would not be drawn on if this would be before the T-1 auction to be held 30 January or the T-4 auction on 6 February.

A number of developers have expressed concern that the rules may be implemented ahead of these dates, severely impacting the business case used to build their applications.

One developer that submitted at least two projects into CM pre-qualification told CEN in September that to do so would “lack common sense”, as it would see a number of projects likely pulled from the CM at a time when government has expressed its intention to promote energy storage.

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National Grid announced this week that its project for a 48 megawatt-hour battery energy storage system on the island of Nantucket has been greenlit and Tesla has been selected to provide the batteries.

Nantucket is a small island of about 10,000 permanent residents about 30 miles off the Massachusetts coast, but it’s also a very popular touristic location.

The island’s electricity is currently supplied via two submarine cables that connect to the mainland transmission system on Cape Cod.

It results in a critical failure point, but the island’s power is still secured with two six-megawatt diesel generators acting as backup power.

Now National Grid explains that those two generators are reaching the end of their useful life and need to be replaced.

The company is looking ahead and sees that the island’s electricity demand is increasing and they would likely need to add a third submarine cable within the next decade or so.

Therefore, they instead suggested the 6 MW/48 MWh battery energy storage system with only one new generator. This way, the battery system can act as backup for short interruptions in power and the generator can kick in to recharge the batteries if needed.

But maybe more importantly, the battery system will also serve to reduce peak demand from the island and stabilize the grid.

With this system, National Grid believes that they can delay adding a third submarine transmission line by at least another decade.

Rudy Wynter, president and COO of National Grid’s FERC-regulated Businesses, commented on the announcement yesterday:

“The BESS provides a very efficient and effective solution to two major energy challenges facing the island. Our customers, communities, and policymakers look to us to deliver innovative solutions like this to help advance our clean energy future.”

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At Massachusetts Institute of Technology’s (MIT) EmTech conference last week, Italian luxury car manufacturer Lamborghini unveiled a new concept electric supercar — and they weren’t kidding when they called it “the future of sports cars.”

The Lamborghini Terzo Millennio (which is Italian for the “third millennium”) certainly does look like it belongs to a future era. The product of a unique collaboration between MIT and Lamborghini, the Terzo Millennio doesn’t just lookthe part of a futuristic car, it’s  packed with next generation technology.

One of the highlights is its energy storage capacity. According to Road Show, the Terzo Millennio uses supercapacitors instead of regular batteries. Coupled with high storage capabilities, supercapacitors are also capable of receiving and delivering a charge faster than standard batteries. Plus, it carries more charge cycles than most batteries, which can supply power to the supercar’s four electric motors — one for each wheel.

Its energy storage capabilities don’t end there, though. The car’s carbon fiber body allows the entire vehicle to work as one big energy storage medium — almost like a battery on wheels.

“If I have a super sports car and I want to go the [race track], I want to go one, two, three laps without having to stop and recharge after every lap,” Mauricio Reggiani, head of R&D at Lamborghini, told CNN. 

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Utilility Integrated Resource Plans (IRPs) are beginning to catch up with the growth of energy storage.

Utilities across the country from Duke Energy Carolinas to Southern California Edison have implemented energy storage projects for a variety of reasons, but until now few have included energy storage in their IRPs. Now, utilities in states ranging from Indiana and North Carolina to Arizona, New Mexico and Oregon have included energy storage in their long term planning processes.

Portland General Electric’s 2017 IRP proposes five storage projects in a range of sizes and applications. The utility’s IRP is, in part, a response to a state law passed in 2015, HB 2193, that required PGE to procure at least 5 MWh of energy storage and up to 1% of 2014 peak load (38.7 MW) by 2020.

PGE’s rationale for including storage in its planning process is the need to support grid flexibility as its use of variable renewable resources grows. Last year more than 40% of the energy PGE delivered was from carbon-free sources. The state’s renewable portfolio standard mandates that 50% of electricity sales come from renewable sources by 2040. PGE says that if hydropower resources are included, it will hit 70% carbon-free energy by 2040.

In its 2017 IRP, PGE says it plans to install a microgrid battery storage pilot project at existing solar and biomass facilities to improve resilience; a battery at a substation to provide energy and capacity and other ancillary services; a storage asset at the existing 1.75 MW Baldock solar facility; up to 500 residential behind-the-meter batteries that would be controlled by PGE to pilot the development of a residential storage program; and a 4 MW to 6 MW transmission-connected storage device that would create a hybrid plant at PGE’s Port Westward 2 facility.

Despite the fact that some of the projects are called “pilots,” they will all be commercial scale, PGE spokesman Steve Corson told Utility Dive. An explicit part of PGE’s strategy, he said, is “to explore a diverse range of technologies in a diverse range of applications and sites so we can learn in addition to having the assets themselves.”

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This morning, the Energy Storage Association released its whitepaper “35 X 25: A Vision For Energy Storage,” which lays out a plan for deploying 35 gigawatts (GW – a gigawatt equals 1,000 megawatts) of storage by 2025. The report – developed in collaboration with Navigant Research – outlines a number of developments that argue in favor of energy storage, including:

• a growing need for grid reliability and resiliency, especially as more critical networks like transportation, HVAC, manufacturing, and data become increasingly electrified and demanding on our aging infrastructure;
• an economy that is becoming more dependent on sophisticated computer networks and society becomes increasingly automated and interconnected;
• a rapid increase in deployment of cost-effective renewable resources, which will benefit from having storage as a dance partner;
• an increasing need for a more flexible and adaptable power grid that will benefit from storage resources that are modular and require short development lead times;
• a dynamic of continuing improvements in storage technologies; and
• a steady and rapid decline in costs – especially for lithium ion batteries, which are expected to shoulder much of the burden

A view from the bridge

It is by ESA’s own admission, an ambitious plan. However, in a conversation prior to the report’s release, ESA CEO Kelly Speakes-Backman expressed confidence that these trends are aligning to help realize this vision. A large infusion of storage can add tremendous value to the grid and to society.

Speakes-Backman noted that while the storage addressed in the report includes all energy storage technologies, many stationary storage deployments will utilize lithium-ion technologies, and that associated costs are dropping steadily, benefiting from economies of scale resulting from their use in consumer electronics and electric vehicles. Over time, she observed, supply chains will continue to become more efficient, further driving down battery costs. And – similar to the experience in the solar industry – affiliated costs, ranging from customer acquisition and financing to inverters and balance of system, will plummet as well.

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As an increasingly high proportion of energy grids are fed by renewable energy, developing storage solutions that can deal with intermittency in sustainably, safely and cost-effectively is key.

Lithium-ion batteries are still the frontrunner technology for large-scale energy storage, and their benefits are clear — high energy densities, relatively low maintenance and a rapidly dropping cost per kWh. But their drawbacks of limited lifespans, explosive failure modes and potentially precarious chains of component supply are equally well publicized.

What battery technologies and chemistries are making waves for stationary storage applications?

All-Iron Flow Batteries (RFB)
Redox Flow Batteries (RFBs) are hardly a new technology, but have received renewed interest in the past few years as grid energy storage solutions. Benefits include long lifespans, theoretically limitless scalability and long discharge times, however, they have been held back by their drawbacks including low energy densities, expensive component costs and in some cases toxic or dangerous electrolyte materials.

Energy Storage Solutions (ESS) have been working on developing and proving the commercial case for their all-iron flow battery which aims to solve several of these issues. In contrast to Vanadium flow batteries, the electrolyte materials are selected for their abundance, safety and low-cost — salt, iron and water. The battery can be transported “dry” and hydrated on site, also lowering logistics costs and improving mobility.

The non-corrosive electrolyte also allows for cheaper materials to be used for the power stack and other battery components. With a mild electrolyte pH (1 to 4) electrode reaction potential lower than the 0.8V carbon corrosion potential, all-iron flow batteries experience little electrode degradation — ESS’s modules experience minimal performance loss over 20 000+ cycles with approximately 70% peak round trip efficiency.

ESS are testing the business case under a contract with the U.S Army Corps of Engineers, with initial cost estimates at have set an estimated cost for their battery at $500/kWh. At this relatively early stage of development, the cost is certainly not attractive enough to compete with Li-on or even Vanadium flow on a wide scale but could be an ideal solution for smaller and/or remote grids.

Aqueous soluble ferrocenes (RFB)
Researchers from Harvard John A. Paulson School of Engineering and Applied Sciences (SEAS) have made great strides in developing flow batteries using aqueous soluble organic electrolytes. These have the advantage of being non-corrosive and non-toxic — not only are they safer, but the component parts can be made of cheaper, less durable materials.

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