Fortescue Metals Group autonomous drilling rig in the Pilbara, Western Australia. Image: Fortescue Metals Group.

A public consultation period has opened on plans for a vast renewable energy project including large-scale battery storage which would be used to power mining operations for Australian metals company Fortescue. 

Fortescue Metals Group has submitted its Uaroo Renewable Energy Hub proposal to the Environmental Protection Authority of Western Australia, with the public consultation period now open for a week until 15 February.   

According to documents hosted on the Authority’s site, the project, in the mineral rich Pilbara region of Western Australia, would consist of up to 340 wind turbines and a solar farm, which between them would have a maximum energy generating capacity of 5.4GW. 

Repurposing land used mostly for cattle grazing, the site proposal also includes substations and other infrastructure and hosting up to 9,100MWh of battery storage, which would comfortably make it the largest battery project in the world. 

The world’s largest battery storage project to date is the 1,600MWh Moss Landing Energy Storage Facility in California, although recent plans were announced to take that up to 3GWh.  

The Pilbara Uaroo Renewable Energy Hub would take up to seven years to construct and have a maximum project life of 42 years, although infrastructure would be maintained and then replaced approximately every 30 years as assets reached their end of life. 

The application has been made by Fortescue’s subsidiary Fortescue Future Industries (FFI) and its energy asset arm Pilbara Energy. FFI aims to drive the group’s transformation into a powerhouse of the energy transition economy, with its other activities including a heavy emphasis on promoting green hydrogen, of which Fortescue founder and chairman Dr Andrew Forrest is an enthusiastic supporter. 

Mining operations, which are often remote and not connected to national or regional grid infrastructure, can benefit both economically and environmentally from onsite or nearby renewable generation backed with energy storage, due to their otherwise being dependent on expensively transported fossil fuels and their attendant, maintenance-heavy generation equipment.

Numerous recent projects have been reported on from this sector, including the recent completion of BHP’s first off-grid renewables projects, with solar PV and battery storage, also in Western Australia. The vast majority however, pertain to reducing site emissions and increasing penetration of renewables, rather than completely powering operations with solar and wind, as appears to be the case with the latest Fortescue project proposal.

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Scania battery electric truck with roadside charger in Sweden. Image: Dan Boman / Scania

Sweden’s largest electric vehicle (EV) truck charging park will be completed later this year with a 2MW battery energy storage system (BESS) and, approvals permitting, 500kW of connected solar, the CEO of the haulier behind it has exclusively told Energy-storage.news.

Falkenklev Logistik has hired solar solutions provider Soltech Energy to build the BESS while vehicle manufacturer Scania is developing the 22-DC-station in partnership with Finnish EV charging specialist Kempower, the companies announced last week. 

The charging park with all grid connections will cost SEK18 million (US$2 million) while the BESS comes to SEK20 million, Falkenklev CEO Victor Falkenklev told Energy-storage.news. The Swedish environmental protection agency Naturvårdsverket is funding half of the park’s cost, according to Scania.

The storage and charging station are in addition to the ongoing development of a nearby 1.5 hectare solar park by Soltech for Falkenlkev, announced last month and costing SEK7.5m. The solar facility will feed electricity into the grid, rather than to the EV park.

Regarding the lack of connection with the charging park, Falkenklev says it is “shopping around for different electric companies that could buy the solar power from Perstorp and sell us a different solar power”.

Falkenklev’s is one of a growing number of projects attaching energy storage to EV charging parks to reduce peak load on local electricity grids and achieve carbon neutrality, either by pairing with renewables or simply better controlling when it charges from the grid. 

Stationary energy storage in support of EVs could reach a global installed capacity of 1.9GW by the end of 2029, according to an August 2020 Guidehouse Insights report as covered by Energy-Storage.news. 

Theirs isn’t the first EV-plus-storage project in Sweden but it’s much larger than the 220kW/320kWh BESS using lithium-ion attached to an EV charging station park in Vasteras, delivered in late 2020 by battery producer Northvolt and publicly-owned utility Mälarenergi. There, the BESS was intended to reduce peak electricity demand of the station by 80%.

Energy-storage.news reported on New York’s first such project, a 5MW/15MWh BESS connected to an 18-station EV charging park for which UK energy giant Centrica won a project tender in mid-2021, put out by utility Con Edison. 

These projects aren’t limited to lithium-ion either. In November, pilots to pair vanadium flow batteries with EV charging stations in Australia and South Korea were announced. 

But the holy grail for these kinds of projects is a direct pairing with a renewable power source, which would allow the low-carbon generation, storing and release of power in a self-contained system with as little reliance on the grid as possible.

Thought to be Europe’s largest EV charging station when it opened in November 2020, the Seed & Greet charging station in Germany pairs 336kWp solar PV, two wind turbines with a 2MWh BESS, powering 114 charging points. It uses a Tesvolt battery system with an expected lifecycle of 30 years.

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CCAs are targeting ever-growing shares of clean energy for their customers. Output from this solar-plus-storage project has recently been contracted for by San Jose Clean Energy, a CCA also based in Silicon Valley. Image: SJCE / Terra-Gen.

An eight-hour duration lithium-ion battery project was recently selected as a long-duration energy storage resource by a group of energy suppliers in California. Girish Balachandran, CEO of Silicon Valley Clean Energy, tells us about the deal and what it signifies.

Regular readers of Energy-Storage.news will likely be aware of the increasing role played in California’s energy landscape — and more specifically its clean energy landscape — by Community Choice Aggregators (CCAs).

Non-profit electricity suppliers allowing their member-customers to choose which sources their power comes from, CCAs are signing ever-greater volumes of contracts for solar, wind, renewables-plus-storage and standalone energy storage resources. 

According to CAlCCA, an organisation which works to support numerous CCAs at legislative and regulatory level, as of November last year power purchase agreements (PPAs) had been signed for more than 2.6GW/9.2GWh of battery storage with average contract length being 17 years, by California’s CCAs. 

But it isn’t just the sheer scale of resources being contracted for. The fact that many CCAs and their customers are opting for greener sources of energy is leading to innovation in contract structures too. 

For instance, yesterday Energy-Storage.news reported on a solar-plus-storage PPA between CCA San Jose Clean Energy and renewable energy developer Terra-Gen which will see 62MWac of clean energy delivered seven days a week, for 16 hours a day, including the critical 6pm to 10pm peak. 

A group of CCAs also proactively moved towards procuring long-duration energy storage resources as early as 2020. When the regulator, the California Public Utilities Commission (CPUC), put out a historic requirement for California’s energy providers to procure a portion of long-duration storage in its Mid-Term Reliability ruling last year — ensuring lights stay on as the state retires gas and nuclear facilities in the coming years — the CCAs were ready.

Power system planning is not what it used to be

In January, the first 69MW/552MWh long-duration storage procurement was announced by seven member CCAs in CC Power, a Joint Powers Agency formed to collectively represent a total of 10 CCAs. 

What surprised many about the contract with developer REV Renewables for its Tumbleweed battery project is that Tumbleweed is a lithium-ion battery energy storage system (BESS). There had been an expectation from some industry commentators — although admittedly not others — that flow batteries, or some form of thermal or mechanical energy storage might have been the frontrunner in a long-duration procurement. 

Energy-Storage.news spoke with Girish Balachandran, CEO of Silicon Valley Clean Energy (SVCE). SVCE serves 270,000 residential and business customers across 13 communities in California’s Silicon Valley. It was one of the seven groups to have signed that contract with LS Power subsidiary REV Renewables. 

The contracts await approval from the elected boards of SVCE and the other CCAs, but Balachandran was able to offer both a background to the role of CCAs today, how that fits with California’s SB100 clean energy by 2045 mandate and the long-duration procurement, which as the CEO says, is ongoing. 

California passed a law in 2002 allowing communities to purchase power on behalf of residents and business, leading to the launch eight years later of MCE, California’s first Community Choice Aggregator. After the formation of MCE in 2010, a wave of other new CCAs sprung up between 2016 and 2018. 

“Community Choice agencies are essentially governments coming together to buy electricity in bulk,” SVCE’s Girish Balachandran says.

“We’re called load-serving entities and our basic span of influence is early on the supply side. Transmission and distribution still stay with the investor-owned utilities (IOUs) and so all customers are opted in to our service and they can opt out if they want.”

While different CCAs have different missions in terms of how to serve customers, from lowering costs or perhaps increasing reliability of local supply, on average CCAs provide greener power than California’s three main IOUs, PG&E, SDG&E and SCE. 

SVCE is providing carbon-free electricity to all of its customers and since its inception in 2017 has been doing this at a discount to the supply rates of PG&E, the service area’s IOU. With its power 50% from wind and solar, SVCE realises that going further will require more and more energy storage. 

“We all recognise in California — load serving entities, regulators — that all the solar coming in during the day has resulted in a Duck Curve and so now we no longer have a peak in the middle of the day, which used to be what utilities planned for for 100 years.”

California’s (in)famous Duck Curve. Image: CAISO.

Having planned the entire power system around an afternoon peak, including the planning of reserve margins, California’s profile has shifted to a ‘net peak,’ during the nighttime hours. 

“So that gets to energy storage, where it is essential to have energy storage to meet the net peak, because you’d have excess renewables from solar dumping into the grid during daylight hours. And now the peak has moved to nighttime hours,” Balachandran says. 

“So we need dinnertime power, we already have excess lunchtime power. That’s where energy storage comes in.”

Are your resources… adequate?

CPUC has mandated that all load-serving entities procure a certain amount of energy storage, from four and five-hour duration storage to longer durations. This includes California’s Resource Adequacy contracting, which means ensuring electricity supplies can be maintained over four and eight-hour periods. 

It’s effectively a long-term contracted capacity payment for availability and is largely what has led to the boom in four-hour duration lithium-ion battery projects in the state. 

Since 2017, SVCE has put out three requests for proposals (RfPs) including contracting for nearly 200MWh of battery storage. Its first facility is coming online soon, and the group hopes to be able to cost-effectively utilise battery storage by combining revenue streams from RA, from arbitrage and ancillary services.

However going into the future, eight-hour energy storage is going to become increasingly important, and it’s likely much longer, perhaps seasonal storage will be needed for a 100% carbon-free grid, Balachandran says. CPUC’s Mid-Term Reliability ruling also mandated for at least 1,000MW of eight-hour storage out of a total 11.5GW resources procurement. 

SVCE and several other CCAs have been “leaning into” the growing need for energy storage, having recognised that the net peak needed to be met. 

Collectively, they put out their request for information (RFI) for long-duration storage in June 2020, before the Mid-Term Reliability ruling, “just to get a sense of what was out there in the market”.

“The kind of information we got was very encouraging,” the CEO says. 

“Both in terms of the diversity of technologies, [and] the duration, it was just very positive to us. There was enough out there in terms of interest that basically confirmed to us, we needed to put the request for offers (RFO) out as soon as possible. When we put it out in October 2020, there was a very positive response.”

From this “diversity of technologies,” it was lithium-ion, presumably the most established energy storage option — albeit at shorter durations — that was selected. So what convinced SVCE and the six other participating members of the CC Power agency this was the right choice?

“It’s a little nuanced. I don’t think the question ought to be about how lithium-ion won over emerging technologies. That’s not it — there is so much [storage] that we need.”

The requirements of the final request for proposal that the CCAs put out was for an eight-hour minimum discharge duration resource of at least 50MW. Contracts would have a minimum delivery term of 10 years for resources to come online by 1 June 2026, while the CCAs would need full deliverability to be eligible for Resource Adequacy credit. Projects had to connect to the CAISO grid, or if not, to ensure full transfer rights for power delivered for SVCE and the other aggregators.  

“We did this before the Mid-Term Reliability requirements were put out, but this kind of aligned [with that].” 

Balachandran is at pains to point out that the contract with REV Renewables for its Tumbleweed BESS is only the first procurement step of a likely many to come. Tumbleweed meets 55% of the Mid-Term Reliability procurement SVCE has been ordered to make. The remaining 45% is to be determined and as he says, there will be more energy storage required between now and 2045. 

The CCAs needed to find an immediately compliant solution to their mandated procurement needs, but really did want to dig into the different options out there in terms of technologies. In the end, three projects have been short-listed through the RFO: two lithium-ion and the other an emerging technology which Balachandran isn’t able to disclose at this stage. 

Undisclosed, but certainly short-listed. Referring to a recent 226MWh vanadium flow battery storage announcement by Central Coast Community Energy, another CCA, Balachandran says that over the next couple of years, we can expect to see a big mix of technologies contracted for in California’s energy storage sector. 

Lithium-ion, with its scalability, will likely take the lion’s share, but flow batteries and other emerging technologies could be a part of that too. 

Aerial view of Gateway, an existing 250MW/250MWh lithium-ion BESS project built in California by LS Power and now in REV Renewables’ portfolio. Image: LS Power.

The RFO was responded to by 51 different entities, representing more than 9,000MW of projects. 

There were aqueous air batteries, iron redox and vanadium flow batteries, zinc and of course lithium-ion batteries. Competing with those were compressed air, hydrogen fuel cells, gravity storage, pumped hydro and then a variety of thermal energy storage technologies like molten salt and liquid air.

It’s very likely some or all of those will have a role to play in future, Balachandran said, they just weren’t the first to be contracted for. 

The CCAs had a scoring rubric which assessed bids on a number of factors. Cost-effectiveness was the primary factor in this instance and the metric on which lithium-ion got the highest score, but also a major factor was REV Renewables and its parent company’s strong track record in the sector. 

So much is changing in California — and the world’s — energy system. Keeping the lights on affordably while decarbonising rapidly is going to be a tricky balancing act, Balachandran says, and while the state is broadly on the right track in his opinion, it needs to be careful how it moves forwards.

“We need to move fast — but let’s not move so fast that we make things unaffordable and the lights go out. We are in a climate crisis, so we really need to be really pushing the envelope, which is what CCAs are doing — but we have had blackouts [in California]. So I think we really need to be very thoughtful about that, and it’s a tough problem, because, we have a [power] shortage. 

“I think there are market structure issues, there are regulatory structure issues that need to be solved.” 

Nonetheless, Girish Balachandran says energy storage will be one of the main tools in the toolkit to solve those challenges and is “very optimistic that there are going to be a variety of technologies, from one-hour storage to multiple days, seasonal storage. We need all of it,” he says. 

“I feel very optimistic about the energy storage business just transforming, and also from a size standpoint. From very large, pumped storage projects, compressed air energy storage projects, to storage in people’s garages, for resiliency purposes and affordability purposes. So it really is an ‘all of the above’ that we’re looking at.

“CCAs are really leaning into getting a lot of carbon-free energy, and trying to make it be as 24/7 as possible.”

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Rendering of Riverina, a 200MWh battery storage project under development in New South Wales. Image: Edify.

The Australian state of New South Wales (NSW) has received proposals for more than 34GW of solar, wind and energy storage for its South-West Renewable Energy Zone (REZ), more than 10 times the likely capacity of the site.

NSW, through its recently formed Energy Corporation that will oversee the state’s REZs, held a registration of interest (ROI) in October and November 2021 for the South-West REZ, which is one of five planned zones in Australia.  

In total, 49 applications from renewables and storage developers made up the 34GWs of proposals, which was 13 times the intended capacity for the REZ, according to James Hay, Energy Corporation CEO, adding that the REZ will be no less than 2.5GW in capacity.

The South-West REZ is to be located to the west of the city of Wagga Wagga and straddle the state’s border with Victoria. 

To read the full version of this story, visit PV Tech.

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One of Standard Solar’s community solar projects in Minnesota

Standard Solar Inc. has acquired a 6.97 MW, 17,785-panel community solar project in Trenton, Maine. This acquisition adds to the company’s existing 50 MW portfolio in the state.

“This newest addition to our ownership portfolio in Maine signifies an important step in our push to bring cleaner energy to business and communities and our nation closer to its decarbonization goals,” says Harry Benson, director of business development at Standard Solar. “Standard Solar is always seeking opportunities to fund and acquire additional projects, and we were quick to capitalize on Maine’s 2019 decision to embrace policies that support solar growth.”

The project, part of the state’s Net Energy Billing (NEB), will bring a 15-25% energy savings to nine leading Maine businesses who have subscribed, sharing the benefits without having to connect to it or invest in its development. NEB, overseen by the Maine Public Utilities Commission, enables businesses and municipalities to receive financial benefits from clean energy produced by a local solar array.

Trenton’s first large-scale community solar project will bring clean energy savings, local economic development and increased resiliency to these area businesses for many years.

“We expect community solar to be a critical part of Maine’s energy mix going forward,” adds Benson.

The solar farm will generate an estimated 10,345 MWh of clean energy each year. The project utilizes bifacial solar modules – double-sided panels that will help the system generate an additional 15% of output from ground reflection, something particularly advantageous given Maine’s snowy winters. The project is expected to be completed by summer 2022.

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Black & Veatch has been selected by Silicon Ranch Corp. to build a sprawling, 125 MW AC solar array in Lee County in southwestern Georgia. Once construction is completed later this year, the DeSoto I Solar Farm will be among the biggest solar installations in the Southeast.

Nashville-based Silicon Ranch developed and is funding the project and will own, operate and maintain it for the long-term, a disciplined approach the company takes with every project it develops.

“As renewable energy continues to progress in a world rapidly focusing on decarbonization, this effort further demonstrates how carbon footprints can be minimized without disrupting the surrounding ecosystem,” says Paul Skurdahl, Black & Veatch’s senior vice president of renewable solutions. “This project aligns with our proven record of innovative approaches to delivering clean, affordable energy.”

DeSoto I will integrate Silicon Ranch’s trademark Regenerative Energy land-management model, which co-locates solar energy production with regenerative agriculture practices. Once construction is complete, Silicon Ranch will restore the land to a functioning grassland ecosystem while keeping the project in agricultural production through managed sheep grazing using regenerative land management practices.

“As the long-term owner and operator of our projects, Silicon Ranch is committed to supporting the communities we serve, and we’re pleased to work with Black & Veatch to execute this vision in Lee County,” states Reagan Farr, Silicon Ranch’s co-founder and CEO. “Thousands of Georgia residents have already helped us build more than a dozen world-class facilities in the region, and we will work with Black & Veatch and our partners in Lee County to recruit local talent for DeSoto I as well.”

Image: Photo by Jadon Kelly on Unsplash

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Josiah Mault

The Renewables Consulting (RCG), an ERM Group company, is ramping up its North America team in anticipation of significant growth with the appointments of Josiah Mault and Jesse Broehl. Over the coming months, RCG plans to accelerate its hiring in North America to as many as 30 staff through a combination of local experts and experienced offshore wind professionals.

Josiah Mault joins RCG as a principal and will be based out of Boston. An experienced professional in wind resource and energy assessment, Mault was formerly the senior team leader and offshore energy assessment lead at DNV.

Jesse Broehl is a principal and will be based out of RCG’s New York office. Before joining RCG, Broehl was an experienced research analyst and has held senior research positions with the American Clean Power Association and Guidehouse Research (formerly Navigant Consulting).

“Renewable energy in the Americas is booming and RCG is an enviable position to help developers, organizations and institutions pursue in their low-carbon ambitions,” says Doug Pfeister, managing director for the Americas. “The appointments of Josiah and Jesse not only bolster our core competencies but also signal a period of rapid expansion in North America.”

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NewHydrogen Inc. is beginning to provide green hydrogen generators to intermittent renewable power sites, such as wind and solar farms, to demonstrate economic viability and new technology under development. Under the terms of a manufacturing supply agreement, Verde LLC, a Massachusetts-based manufacturer of green hydrogen generation systems, will supply the company with hydrogen generation systems.

“We are very excited about our new business relationship with Verde and our plan to partner with operators of intermittent renewable power sites, such as wind and solar farms,” says David Lee, CEO of NewHydrogen. “Verde will manufacture the systems for NewHydrogen, which the company will purchase for use at the sites.”

The company is targeting wind and solar farms which produce excess solar and wind energy during certain times of the day. This power can be used to run an electrolyzer (the primary component in a hydrogen generator) that converts water into green hydrogen, which is distributed in pipelines and converted back into electricity when needed. This green hydrogen can be stored in tanks and underground caverns, forming a network that can energize industry and back up electric grids. Having the flexibility to redirect unused energy capacity into making fuels can fill the gap between constant energy demands and variable energy resources.

“For NewHydrogen, this is a major leap forward,” Dr. Lee adds. “By owning and controlling the hydrogen generators at these sites, we will be able to move very rapidly to demonstrate the economic viability of this approach, as well as new technology currently under development including our breakthrough catalysts.”

The goal of NewHydrogen’s sponsored research at UCLA is to lower the cost of green hydrogen by eliminating or drastically reducing the use of precious metals in electrolyzers. Electrolyzers currently rely on rare earth materials such as iridium and platinum. These materials often account for nearly 50% of the cost of electrolyzers.

In 2021, the sponsored program at UCLA developed a non-precious metal-based catalyst with significant improvement of oxygen evolution reaction (OER) in acidic conditions for proton exchange membrane (PEM) electrolyzers. Researchers then improved the catalyst performance by modifying the structure and optimizing loading conditions. Most recently, application of a unique surface engineering technique further improved the long-term stability of the catalyst. Higher stability implies reduced operating cost of electrolyzers in the longer term.

In a parallel effort, researchers have been developing hydrogen evolution reaction (HER) catalysts for alkaline electrolyzers. Their work is focused on developing platinum based HER catalysts that use significantly less platinum, as well as a totally new type of HER catalyst that does not use platinum at all. To date, significant progress has been made on both fronts. This is in line with the Company’s focus on developing OER catalysts to enable electrolyzers that cost less to manufacture and to operate.

“Prior to scaling up the process for studies with a prototype electrolyzer in late 2022, researchers will continue to explore additional improvements to both the OER and the HER catalysts to maximize the overall performance of an actual water electrolysis device,” Dr. Lee concludes.

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Image: Andy Colthorpe / Solar Media.

Responding to increasing demand for dispatchable renewable energy resources, GE Renewable Energy has opened a factory for ‘Renewable Hybrid’ technology solutions and equipment in Chennai, India. 

It will manufacture the company’s containerised inverter solution, FLEXINVERTER, which is claimed to be a plug and play unit suitable for solar and energy storage applications at utility-scale, and FLEXRESERVOIR, an integrated battery energy storage and power electronics solution which can be flexibly configured to deliver multiple market applications. 

Both products will also be integrated into GE Renewable Energy’s new digital platform, FLEXIQ, which enables customers to design projects, operate them and manage them at fleet level. The company claimed FLEXIQ enables grid compliance as well as maximising customer lifetime value. 

Apparently the factory employs 250 workers, which was the only indication given by GE Renewable Energy of its size and production capacity. Energy-Storage.news has asked for further details on those metrics, as well as on any plans to ramp up production in response to customer demand, but had yet to receive a reply at the time of publication. 

“As the industry and customers’ demand dispatchable renewable energy to navigate the energy transition, the need for hybrid systems is increasing exponentially,” Prakash Chandra, CEO for Renewable Hybrids at GE Renewable Energy said as the factory’s opening was announced yesterday.

FLEXRESERVOIR is scalable from a rated power of 3MW to 500+MW with the addition of more inverters, with durations of less than an hour to more than four hours with the addition of more battery storage units. 

FLEXINVERTER is available as a solar PV inverter, or for use with battery energy storage systems (BESS), with DC and AC coupling configuration options and advanced grid features and reactive power control. 

The FLEXIQ plant control platform provides integration for standalone solar PV, PV-plus-BESS and PV-plus-wind-plus-BESS configurations, accommodating AC and DC coupling as well as standalone configurations. It can manage voltage, power factor and reactive power capabilities, and incorporates PV signals into the SCADA at overall plant level. 

GE Renewable Energy said the new factory will be able to full produce and integrate systems on site. It is in a central location with national highway connections, as well as accessibility to air and sea transport routes, the company said.  

In a recent report into India’s lithium-ion battery manufacturing space, issued by research group JMK Research and Analytics with the international Institute for Energy Economics and Financial Analysis (IEEFA), it was pointed out that renewable energy sector-driven demand for battery storage is expected to grow significantly in the country. 

While 90% of battery demand will be driven by the automotive sector, grid-scale energy storage will be needed, not least of all to help integrate the 450GW of renewable energy resources the government aims to have online in India by 2030. 

The country already has fairly well established domestically-located battery pack manufacturing facilities, but is yet to move forward on large capacity additions of battery cell production, the report said. The Union government is looking to support advanced chemistry cell manufacturing with incentives for up to 50GWh of production facilities from foreign or Indian companies building factories in the country. 

According to JMK and IEEFA, a large market for grid-scale battery storage in India is “still a few years away,” largely due to the relatively high cost. As of last March the country only had about 30MW of solar that was paired with just under 20MWh of battery storage at grid-scale but the ongoing addition of renewable energy capacity will drive demand for projects supported by BESS to firm up that power output.

“With the need for an assured renewable energy-integrated power supply bound to grow significantly in the future, lithium-based BESS will become critical in this (grid-scale renewable energy integration) market segment,” the report said.

In the country’s most recent Union Budget, announced last week, energy storage systems became eligible for classification as infrastructure, opening up pathways for loans and investment financing in a move warmly welcomed by the industry. This followed the Ministry of Power issuing a clarification of the status of energy storage systems in India’s power sector, describing the technologies as “essential” to achieving renewable energy aims.

International energy storage tech provider Fluence has said it will launch a joint venture to take on the Indian market with one of its biggest players in renewable energy, ReNew Power, later this year.

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An example of a neighbourhood battery system in West Australia, installed in a
trial by Western Power. Image: Western Power.

Sometimes called ‘community batteries,’ energy storage systems are being installed at neighbourhood level in Australia. Experts from the Australian National University explain how this type of battery storage can benefit a very wide range of stakeholders.

This is an extract of an article which appeared in Vol.29 of PV Tech Power, Solar Media’s quarterly technical journal for the downstream solar industry. Every edition includes ‘Storage & Smart Power,’ a dedicated section contributed by the team at Energy-Storage.news.

As Australia transitions its electricity supply away from fossil fuel-powered generators to renewable sources of energy, neighbourhood batteries are becoming an increasingly popular form of storage. There are more than one dozen neighbourhood battery projects currently underway across Australia, with a range of ownership and operation models.

It is now, in the early days of neighbourhood battery research development, design and demonstration that we can evaluate the various models and trade-offs inherent in these models. Technology can end up not meeting user needs, or result in negative unintended consequences if we don’t step back to understand their impacts early on.

In the Battery Storage and Grid Integration Program at the Australian National University we have been conducting numerous studies that delve into the socio-techno-economic aspects of neighbourhood batteries.

Our research has revealed that this type of battery can provide a range of benefits for all energy stakeholders, be they energy network operators, energy retailers, market operators, customers, governments, or local councils.

What these batteries have in common is that they are all located close to customers, connected to the distribution network, and can provide stored energy for up to hundreds of homes.

They range in size from a wardrobe to a shipping container, have power capacities of about 0.1 – 5MW and complement household and utility-scale batteries.

Reversing a trend of ‘haves and have nots’

What makes neighbourhood batteries a particularly interesting form of energy storage is that they have the potential to address energy equity and provide benefits to all energy users. Some groups of people, particularly renters and those who do not have solar panels on their rooftops, but also people who might be socially and digitally isolated could all benefit from neighbourhood batteries.

These benefits could be economical, or an increased sense of autonomy and control over their local energy management. This contrasts with how rooftop solar has played out in the Australian context.

Historically residential solar has been a tale of the ‘haves’ and the ‘have-nots’.

Those who can afford to put solar panels on their roof and those who cannot.

Household solar uptake has not happened alongside a broader conversation about what kind of energy system we want. Neighbourhood batteries can hopefully spark those conversations. Our research tells us that people really want to be a part of these conversations and have long felt disconnected from energy decisions that affect them.

Neighbourhood batteries are sometimes referred to as ‘community batteries’ or ‘community energy storage’. We elect not to use these terms because the word ‘community’ implies a degree of community involvement.

Some neighbourhood battery projects absolutely do have this element and we suggest community involvement is required as a principle. It is also the case that other models are allowed in Australia’s current regulatory system that requires little or no involvement from the community. To encompass all models, we use the term neighbourhood batteries.

582kW / 583kWh battery storage system in the remote town of Marble Bar deployed this year by state government-owned electricity supplier Horizon Power. Image: Horizon Power.

Australia, the distributed energy resources superstar

Australia leads the world in the uptake of rooftop solar, per capita, with one in four homes with residential PV. Three million solar systems have been installed nationwide, that’s nearly 1kW of panels per person. It is the enthusiastic adoption of rooftop solar by people that has made the country a distributed energy resources superstar.

Integrating this vast amount of solar generation is a major challenge for network operators and there are several ways Australia is tackling this problem from smart software solutions, utility-scale storage, pumped storage and various demand response and other market mechanisms.

In Australia, also notably in the US states of California and Texas and many parts of Europe, grid operators are resorting to solar curtailment when there is not enough transmission capacity to cope with the generation of renewable energy.

The infamous ‘duck curve’ graph indicates the discrepancy between peak electricity demand versus peak solar energy production. Neighbourhood batteries have a role to play in capturing the excess energy generation and storing it until it is needed. But this is just one of the benefits of this type of battery.

Defining and assessing the benefits

The ability to provide benefits to many stakeholders is one of the key reasons why we felt it was important to comprehensively investigate the opportunities for neighbourhood batteries. There are four key elements that describe a range of possible battery models.

» Battery ownership – who will own the battery, and what regulatory considerations might arise due to ownership? Crucially, how might battery ownership influence the prioritisation of benefits to different stakeholders?

» Stakeholder participation – who is a stakeholder in the battery’s operation, and what is their legal and operational relationship with the battery? How do stakeholders benefit from their participation, and what technology is necessary to enable the battery operation?

» Network tariffs – what network tariffs are applied to energy flows into and out of the neighbourhood battery, and how do network tariffs unlock or impact the benefits that can be delivered to stakeholders?

» Services delivered – what market services, such as energy arbitrage and frequency support, can neighbourhood batteries deliver? What non-market services, such as network support (demand response, voltage regulation), do neighbourhood batteries deliver? How can services be value stacked to maximise the battery’s utilisation and cost-effectiveness? Or maybe, due to community discussion, the most ‘optimal’ outcome may actually be an optimisation they can understand, meaning, perhaps not all value streams will be accessed.

By undertaking a socio-techno-economic analysis of various permutations of these four key considerations, we have been able to assess how different neighbourhood batteries create value for energy users, distribution networks, electricity retailers and the broader electricity system. Our work has so far revealed that neighbourhood batteries can deliver five essential benefits.

They can:1. Improve the fairness of the energy system2. Build trust in the energy system by sharing value transparently3. Increase the hosting capacity of the network4. Bolster local resilience, including socially, economically, and electrically5. Be cost effective by delivering services to many stakeholders.

We note that more benefits may become clear as we roll out this technology at scale.

Artist’s impression of a neighbourhood battery system on a street in Melbourne, Victoria. Image: Pixii

The economics of neighbourhood batteries

The issue of network tariff reform has historically been a contentious one in Australia, in the context of high uptake of household solar. We have studied the operation of neighbourhood batteries under a range of local network tariff models, using current Australian electricity prices and current network prices as a reference.

Our modelling shows that neighbourhood batteries would only be financially feasible if the local network tariff was discounted. This is due to the tariff applying to both the charging and discharging of the battery, meaning the system is double-charged.

Previous proposals to address this issue have generally either applied a discount to network tariffs for local energy flows or created a secondary energy market for peer-to-peer transactions. The former is expected to result in a zero-sum wealth transfer between networks and customers, and the latter has faced implementation and regulatory complexities.

Our modelling, however, demonstrates that a discounted local use of system (LUOS) network tariff could be introduced without the expected zero-sum wealth transfer, if a neighbourhood battery is included in the local system. This is due to the increased number of transactions on the network as the battery charges and discharges, such that the network receives the same revenue even though the network tariff is discounted. Network charges incurred by the neighbourhood battery owner can be offset by the revenue earnt from energy arbitrage.

In this way, all stakeholders (network, customers, battery owner) can be financially better off compared to a system with no neighbourhood battery and the normal network tariff.

The clear recommendation from our analysis is that the price of LUOS needs to be less than half of conventional distribution network tariffs, allowing for mutually beneficial economic outcomes for all stakeholders.

This is an extract of an article from Volume 29 of PV Tech Power, our quarterly journal. You can buy individual issues digitally or in print, as well as subscribe to get every volume as soon as it comes out. PV Tech Power subscriptions are also included in some packages for our new PV Tech Premium service.

About the Authors

Sarah Wilson is communications manager for the Battery Storage and Grid Integration Program at the Australian National University. 

Hedda Ransan-Cooper leads the social research at the Battery Storage and Grid Integration Program at the Australian National Unversity.

Bjorn Sturmberg is a research leader in the Battery Storage and Grid Integration Program at the Australian National University.

Lachlan Blackhall is entrepreneurial fellow and head, Battery Storage and Grid Integration Program at The Australian National University.

Marnie Shaw is a senior research fellow in the School of Engineering and a research leader in the Battery Storage and Grid Integration Program at the Australian National University. 

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