Tesla has been making big moves on the energy storage market in Australia, but they are now all being dwarfed by this new project that will see them install solar arrays and Powerwalls on 50,000 homes to create the biggest virtual power plant in the world.

The company’s main project has been the 100MW/ 129MWh Powerpack project in South Australia, the largest in the world for now.

But now instead of being a large centralized battery system using Tesla’s Powerpacks, the new project announced today is using Tesla’s residential battery system, the Powerwall, to create decentralized energy storage, which basically results in creating a massive virtual power plant.

South Australia Premier Jay Weatherill announced the deal today – the biggest of its kind by far.

The 50,000 homes in the state will be fitted with 5 kW solar arrays and 13.5 kWh Tesla Powerwall 2 battery systems.

It will result in at least 650 MWh of energy storage capacity distributed in the state.

Tesla said in a statement:

“When the South Australian Government invited submissions for innovation in renewables and storage, Tesla’s proposal to create a virtual power plant with 250 megawatts of solar energy and 650 megawatt hours of battery storage was successful. A virtual power plant utilises Tesla Powerwall batteries to store energy collectively from thousands of homes with solar panels. At key moments, the virtual power plant could provide as much capacity as a large gas turbine or coal power plant.”

It will function much like Tesla’s giant Powerpack system, which charges when demand and electricity rates are low and discharges when demand and prices are high.

We reported last month the single battery system managed to make around $1 million in just a few days.

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Tesla is partnering with South Australia’s Labor government to create the world’s largest virtual power plant, consisting of 50,000 homes fitted with solar panels and the company’s Powerwall 2 home battery unit. The $800 million project will have roughly six times more energy storage capacity than Tesla’s massive Powerpack farm at the Hornsdale wind farm near Jamestown.

Initial plans for the virtual grid would begin with low-income, social housing properties, with each house being equipped with a 5 kW rooftop solar system and a 13.5 kWh Tesla Powerwall 2 home battery system. In total, the project is expected to deliver 250 MW of solar energy and 650 MWh of battery storage capacity when complete, while providing grid stability by shifting demand away from a stressed grid during peak hours.

State premier Jay Weatherill expressed his excitement about the virtual power plant that would not only complement Tesla’s big battery project at the Hornsdale wind farm; it would dwarf the 100MW/129MWh Powerpack system many times over as well.

“My government has already delivered the world’s biggest battery, and now we will deliver the world’s largest virtual power plant. We will use people’s homes as a way to generate energy for the South Australian grid, with participating households benefiting with significant savings in their energy bills. Our energy plan means that we are leading the world in renewable energy and now we are making it easier for more homes to become self-sufficient,” he said, according to a RenewEnergy report.

To fund the creation of the world’s largest virtual power plant, the State Government is assisting the release of a $2 million grant and $30 million loan from the Renewable Technology Fund to get the project underway, as noted in the project’s official website. The SA government is also seeking additional funding from private investors. Tesla would be responsible for the installation of the solar systems and Powerwall 2 home battery packs.

Smart Energy Council CEO John Grimes lauded Tesla and the South Australian government for the initiative. Grimes, for one, noted that the construction of the virtual power plant would place the country at the forefront of the green revolution in technology.

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Carbon-free energy: Is the answer blowing in the wind? Perhaps, but the wind doesn’t always blow, nor does the sun always shine. The energy generated by wind and solar power is intermittent, meaning that the generated electricity goes up and down according to the weather.

But the output from the electricity grid must be controllable to match the second-by-second changing demand from consumers. So the intermittency of wind and solar power is an operational challenge for the electricity system.

Energy storage is a widely acknowledged solution to the problem of intermittent renewables. The idea is that storage charges up when the wind is blowing, or the sun is shining, then discharges later when the energy is needed. Storage for the grid can be a chemical battery like those we use in electronic devices, but it can also take the form of pumping water up a hill to a reservoir and generating electricity when letting it flow back down, or storing and discharging compressed air in an underground cavern.

Motivated by a view that storage is a “green” technology, governments are increasingly promoting utility-scale and distributed energy storage. For example, in November 2017, New York Gov. Andrew Cuomo signed a bill mandating targets for storage adoption by 2030. Other states with similar policies are Oregon, Massachusetts, California and Maryland. Companies like Tesla also have been branding storage systems as clean technologies.

But do large storage systems lower emissions in our current grids? In a recent study, we found this isn’t necessarily the case – a reflection of how complex the electricity system can be.

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The first large-scale commercial plant was built in Huntorf in Germany and has now been in successful operation for many years.

The reason for the slow progress of CAES is the prohibitive cost of a suitable storage vessel. Large CAES schemes have relied on disused underground caverns to provide a reservoir for the compressed air, but these are not readily available and may not be close to a market for electrical energy.

Also, existing CAES plants are not environmentally “green”. Compression of air into the storage reservoir generally relies on compressor power generated by fossil fuel, and recovery of stored energy uses conventional gas turbines burning fossil fuel.

Even if the compressor power is provided by wind turbines, the plant is predominately fossil fuel-powered.

Fresh opportunities

The prospects for CAES could be about to change. Buoyant supports for offshore wind turbines are of increasing interest.

Floating foundations such as the Statoil Hywind type require a substantial buoyancy volume for hydrodynamic stability and this offers an obvious opportunity for storing energy as compressed air.

Figure 1 (below) shows the dimensions of an articulated buoyant column sized for a 6MW turbine in 80m water depth.

Figure 2 (beneath) shows the buoyant column diameters required to achieve sufficient stability for turbines mounted on such columns as a function of turbine power and water depth.

Figure 3 (bottom) shows the total energy that could be theoretically stored in these columns when filled with compressed air at 10 bar.

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In a paper published in Chemical Science, an open access journal of the Royal Society of Chemistry, researchers in the lab of Ellen Matson, assistant professor of chemistry, describe modifying a metal-oxide cluster, which has promising electroactive properties, so that it is nearly twice as effective as the unmodified cluster for electrochemical energy storage in a redox flow battery.

The cluster was first developed in the lab of German chemist Johann Spandl, and studied for its magnetic properties. Tests conducted by VanGelder showed that the compound could store charge in a redox flow battery, “but was not as stable as we had hoped.”

The key to a redox flow battery is finding chemicals that can not only “carry” sufficient charge, but also be stored without degrading for long periods, thereby maximizing power generation and minimizing the costs of replenishing the system.

By making what Matson describes as “a simple molecular modification”— replacing the compound’s methanol-derived methoxide groups with ethanol-based ethoxide ligands—the team was able to expand the potential window during which the cluster was stable, doubling the amount of electrical energy that could be stored in the battery.

 “The straightforward, efficient synthesis of this system is a totally new direction in charge-carrier development that, we believe, will set a new standard in the field,” said Matson.

The electrochemical testing required for this study involved equipment and techniques not previously used in the Matson lab. Hence the collaboration with Timothy Cook, assistant professor of chemistry at the University of Buffalo, and Anjula Kosswattaarachchi, a fourth-year graduate student in the Cook lab. VanGelder visited the Cook lab for training on testing equipment, and in turn helped Kosswattaarachchi with synthesizing compounds.

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In 2017, utility-scale energy storage moved from a handful of experimental programs to front-page news, with prominent deployments in Australia, Texas, Southern California, and hurricane-ravaged Puerto Rico. Building on these successful installations, 2018 should be an even more important milestone for energy storage, as policymakers encourage electricity system operators to include storage in their integrated planning. Regulators will also need to clarify the market rules around energy storage, to allow utilities and other storage operators to “stack” ancillary services on top of storage, as the California Public Utilities Commission (CPUC) recently did.

Energy storage will affect the entire electricity value chain as it replaces peaking plans, alters future transmission and distribution (T&D) investments, reduces intermittency of renewables, restructures power markets and helps to digitize the electricity ecosystem. For utilities, battery storage will become an integral tool for managing peak loads, regulating voltage and frequency, ensuring reliability from renewable generation, and creating a more flexible transmission and distribution system. For their customers, storage can be a tool for reducing costs related to peak energy demand.

Driving all of this opportunity is the decreasing cost of battery storage, a factor largely of the rapid increase in their development and manufacture of batteries for electric vehicles. Research by Bain & Company estimates that by 2025 large-scale battery storage could be cost competitive with peaking plants—and that is based only on cost, without any of the added value we expect companies and utilities to generate from storage. In some markets, renewables combined with battery storage already cost less than coal generation.

Utilities and their large commercial customers are also looking at ways to create more value around their investments in storage, to make deployments more feasible. It’s these stacked services that the CPUC recently addressed in a set of clarifying rules meant to deal with the ambiguity around battery storage. In addition to using batteries to store electricity during periods of low demand and then releasing those stored electrons during peak periods to shave peak loads, stored electricity can provide services like voltage and frequency modulation. And it can ensure greater reliability from intermittent renewable generation.

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Arizona’s utility regulator, Andy Tobin, proposed a new energy modernization plan which will update Arizona’s policies on clean energy, storage, biomass, efficiency, vehicles and more.

The sweeping plant, seems to be an intelligent look at the most modern techniques, combined with pragmatic decision-making – to clean a power grid.

Currently, Arizona has a 15% renewable energy mandate by 2025, a goal which has already been met. This new proposal will see that increase to 80% by 2050, “with the ultimate goal of being 100%.” Nuclear power is included in the clean energy target.

For energy storage, a new target of 3GW by 2030 will be set per the original reporting on the topic by Utility Dive. The proposal cites:

“Low priced, and sometimes free electricity, is being exported from surrounding states; at the same time, increasing peak demand in Arizona is causing new expensive investments for ratepayers.”

The smartest thing I’ve ever heard someone do is taking advantage of ‘free stuff.’ California has paid Arizona take electricity in the past.

This 3GW of storage target is the largest volume target so far, California is second at 2GW – however – California’s number is by 2020. If we compute the targets on a per capita basis – Arizona has 6.9 million people versus California’s 39.2 million – we’d have to see California reaching 17GW of energy storage by 2030.

Bloomberg suggests the USA will have about 75GW of energy storage by 2030 – California has a habit of leading the country, and I expect California to blow past 17GW by then – possibly being as much as (or far more depending on doubling pace) 37.5GW (50% of US total).

Technologies that qualify as energy storage include: electrochemical (batteries), mechanical (flywheels/compressed air), thermal (molten salt), and gravitational (pumped hydro).

The proposal sets a target of 90 MW of biomass generated from the ‘treatment’ of 50,000 forests by the end of 2021. Only “high-risk fuel,” sourced 80% from within Arizona, will qualify toward the 90 MW of required biomass energy production.

In another example of renewables coming for gas peaker plants – Arizona’s new proposal includes a new “Clean Peak Standard”, where utilities will be required to use renewable resources during peak hours – with the logic that it’ll drive energy storage construction.

These renewable fed energy storage plants, simply by existing on the network, will probably also offer ancillary services like the Australia 100MW/129MWh Tesla Battery, but it will also be requested to do something much bigger – eating the ‘duck curves’ that arise as a result of growing daytime solar power production.

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A 3,000MW energy storage target, proposed in Arizona as part of a grid modernisation policy, recognises the role of the technology in reducing the need for fossil fuels to stabilise the grid, a consultant has said.

Yesterday, Andy Tobin of the state’s regulator, the Corporation Commission, presented a plan that includes a goal to generate 80% of Arizona’s power from renewable sources by 2050, a commitment to review the existing Renewable Energy Standard and Tariff (REST) policy, to use renewables to mitigate peaks establishing a ‘Clean Peak’ standard and to deploy 3,000MW of energy storage to “leverage low priced energy during the day”.

The Commission will vote on the proposal in the next couple of weeks. A final vote is expected which would make the regulatory proposal legally binding, within six months to a year, Lon Huber, vice president and head of consulting at Stratagen Consulting, told Energy-Storage.News.

The 3GW target would be the biggest established to date in the US – the first state to set a target, California, is calling for 1.35GW by 2024 and New York for 1.5GW by 2025. While the timeline for deployment is longer for Arizona than those two previous title-holders, Huber pointed out that relative to the state’s size, the figure pencils out at a far higher capacity deployed per capita than in the others.

Lon Huber said the establishment of the target is closely linked to known plans for development of new gas turbine facilities by Arizona’s major utilities, including Arizona Public Service, which is projecting that it will need 5GW of new gas plants by 2032. Huber said it was likely the 3,000MW figure was arrived at as “a fraction of the new combustion turbines in the IRP (Integrated Resource Plans) of the utilities”.

“I think the assessment of what could be cost-effective storage was probably based on the need for new peakers over the next 15 years, more than anything. I think the innovation here is that, depending on different states and how they do things, you could end up in a situation where you buy a lot of renewables but you still need a large fossil backup fleet.”

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The CEO of Orsted, the world’s largest offshore wind developer, has said that his company is working to establish “a scalable commercial model” for solar PV and energy storage, viewing both as potential drivers of long-term growth.  

Danish power company Orsted, formerly known as DONG Energy until a rebrand and restructuring last year that also included selling off its oil and gas businesses, has just reported its latest quarterly financial results, including reporting for the full 2017 year.

For 2017, the group saw DKK22.5 billion (US$3.77 billion) operating profit, an increase of 18% from the year before. This included a 74% rise in profits from its wind business. The company made an overall net profit of DKK13.3 billion (US$2.23 billion), an increase of more than DKK1 billion from 2016.

The report and accompanying statements from the company and CEO Henrik Poulsen reiterated Orsted’s commitment to a transition to a low carbon, green and sustainable energy system repeatedly. The company is aiming to go coal-free by 2023 and also to source 95% of its heat and power generation from renewables by that time.

“Our strategy is based on the vision of an integrated green energy system, where renewable energy technologies can be combined with each other and with energy storage solutions, more flexible and intelligent patterns of consumption and electrification of the transport sector, heating systems and industry,” Poulsen said.

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Marking its entrance into the Japanese battery market, and gearing up to take advantage of the growing self-consumption opportunities in the country, London-based Moixa Energy Holdings Ltd has entered into a partnership with one of Japan’s largest trading houses.

Under the exclusive marketing deal, Itochu has said it will install Moixa’s GridShare platform as a standard, on its products by this summer. Overall, Itochu also aims to sell more than 6,000 units of its “Smart star” home battery systems, which were developed in cooperation with the NF Corporation, by the end of this March.

AI technology

Under the GridShare aggregation platform, Moixa uses AI technology to trade excess power stored in smart batteries owned by partners in the GridShare scheme, with the National Grid. This helps to reduce the load on grids during peak demand, to create a flat grid.

The partners receive a share of the profits in return, the amount of which depends on whether the partner has a fixed income or profit share membership.

“The technology will save customers money by using artificial intelligence to optimise the performance of their battery based on their patterns of behaviour, the weather conditions and market prices,” said Moixa in a statement released.

Expansion

In addition to the distribution partnership, Itochu has said it will invest £5 million (around US$7.1 million) in Moixa to support international expansion.

This follows on from an investment of £500,000 by Japan’s Tokyo Electric Power Company Holdings (TEPCO) last April. Overall, the company raised around £3.5 million in 2017. It is specifically eyeing the European and U.S. markets for expansion.

“Moixa will now seek to expand its GridShare partnerships with Japanese utilities and electric vehicle manufacturers and to market services to electricity networks. It is also planning trials in the US and Europe this year,” read the statement.

In the U.K., the company has already installed nearly 1,000 battery systems. It further holds patents in the U.K., U.S. and Australia on distributed smart battery systems, and aggregating batteries for grid services.

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