Enel X Way, the Enel Group’s global e-mobility business, has partnered with Sunrun, a home solar, battery storage and clean energy service provider, to supply smart Level 2 electric vehicle (EV) charging stations for the company’s recently launched EV charger offering. The new co-branded home EV chargers expand Sunrun’s suite of energy management solutions.

“With one-third of Enel X Way EV charger owners using solar to power their homes, there’s no denying the strong correlation between solar adopters and EV owners,” says Chris Baker, head of Enel X Way North America. “Not only does this partnership mark a pivotal convergence between two adjacent industries, the ability to combine efforts and use solar energy to power charging also furthers our progress toward national decarbonization targets. We’re honored to partner with Sunrun to offer an affordable, smart EV charging solution for climate-conscious customers.”

Enel X Way’s Level 2 EV chargers, which can be grid-connected, work seamlessly with Sunrun’s home solar solutions, enabling customers to charge their vehicles at home using solar energy.

“Home solar and EVs are the perfect match,” states Mary Powell, CEO of Sunrun. “EV owners want to charge their vehicles with a more cost effective, clean, and reliable energy source – saving money and time with home charging convenience. By combining Enel X Way’s EV charging expertise and Sunrun’s ability to right-size home solar systems, we’re helping prepare customers for a carbon-free energy future.”

The co-branded EV charging stations are available in select markets, including California, New Jersey and Vermont, and are expected to be available nationwide by the beginning of 2023. The smart home EV chargers will be sold as an optional add-on for bundling with a Sunrun home solar-plus-battery system.

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Stefaan Sercu

ENGIE North America has completed Chula Vista Elementary School District’s solar project in California. The district now has 8.1 MW of solar installed across 48 sites and is finalizing the installation of a microgrid system. The microgrid is located at the Education Service and Support Center and powered through solar and batteries to provide backup emergency power to the district’s IT department, additional servers and the Child Nutrition freezer. The microgrid’s battery storage system will also provide electricity during peak time periods.

The solar installation includes 18,050 panels installed as shade structures at 46 schools, the Transportation Yard, and the Education Service and Support Center. The $32 million project was funded through a G.O. Bond and is expected to save the district more than $70 million in net electricity costs over the next 25 years.

“That is $70 million in savings even after project costs have been paid for,” says Deputy Superintendent Oscar Esquivel. “By the end of this project, we think we will be able to generate about 90 percent of the district’s overall energy demands. That is a tremendous amount of energy – and savings for our district. This is a ‘green’ project both environmentally and fiscally.”

“We have a demonstrated commitment to strengthening environmental sustainability efforts that our community recognizes,” Esquivel adds. “Our team has done an outstanding job of continually finding ways to increase energy efficiency and savings while doing our part to improve the environment. We want to model for our students the importance of energy awareness, conservation, and sustainability.”

“Our ENGIE North America team is proud to deliver customized solar and microgrid solutions to customers like Chula Vista Elementary School District,” states Stefaan Sercu, managing director of Energy Solutions Americas at ENGIE. “In addition to this technology serving as a critical resource during potential power outages, the bigger picture impact of the district’s move toward sustainable energy ensures long-term financial savings and resiliency.”

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SDG&E executives at the Fallbrook facility. Image: SDG&E.

California investor-owned utility SDG&E has completed construction of a 40MW battery energy storage system (BESS) and started work on four storage-enabled microgrids totalling 39MW.

The utility announced yesterday (12 October) it had started testing on the 40MW project in Fallbrook, a small region between San Diego and Los Angeles, and begun building one of the four microgrid projects. It now has 95MW of utility-owned energy storage and another 200MW in development.

The Fallbrook project is a 40MW/160MWh system, with four-hour duration being a condition for providing capacity to utilities like SDG&E under Resource Adequacy, the California Independent System Operator’s (CAISO) means of ensuring there is enough supply to meet demand, plus a reserve margin. The project will be connected to the state’s energy market once testing has been completed.

The Elliott Microgrid in San Diego, the first of the four being built, will be able to provide power to essential services. Those are the Fire Station 39, the Tierrasanta Public Library (which acts as a Cool Zone during extreme heatwaves), Tierrasanta Medical Center, Jean Farb Middle School, Canyon Hills High School, and Tierrasanta and Kumeyaay Elementary Schools.

“Innovations like storage and microgrids are vital to building a more resilient electric grid that can extend the availability of renewable energy into peak demand hours and better prepare communities to manage through emergencies,” said SDG&E vice president of energy innovation Miguel Romero.

As Energy-Storage.news recently reported, BESS capacity had a major role to play in the CAISO grid’s mitigation of extreme heatwaves sweeping the Golden State. CAISO’s latest figures show it had 4,367MW of BESS connected to the grid as of 1 October 2022.

Recent large-scale projects to have been completed and connected to the grid include AES’ 908MWh system, a 387MW co-located BESS from NextEra and a 200MW one from EDF.

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Vincent Browne

Alternus Energy Group Plc and Clean Earth Acquisitions Corp., a climate technology and energy transition-focused special purpose acquisition company, have executed a definitive business combination agreement. Under the agreement, at the closing, Alternus will transfer its equity ownership in substantially all its subsidiaries in exchange for up to 90 million newly issued shares in Clean Earth.

Initially, Clean Earth will issue 55 million shares at closing (subject to a working capital adjustment capped at 1 million additional shares) plus up to 35 million shares subject to certain earn-out provisions, which will be deposited in escrow and will be released if certain EBITDA and share price targets are met. Alternus will own approximately 64% of Clean Earth at closing, assuming no redemptions by Clean Earth shareholders, in which case the combined company will have approximately $220 million of cash available at closing.

The combined company is expected to have an initial equity value of approximately $863 million, assuming no redemptions by Clean Earth shareholders. The business combination valuation is based on 168 MW of current operating and 649 MW of in-development projects owned by Alternus, plus 845 MW of contracted acquisitions with an additional 800 MW of solar PV projects that Alternus has exclusive rights to purchase subject to due diligence and entering into definitive agreements. Clean Earth’s board of directors received an independent, third-party fairness opinion, which will be included in a proxy statement to be filed with the U.S. Securities and Exchange Commission (SEC).

Closing is contingent on customary closing conditions for transactions of this nature, including Clean Earth shareholder approval, following filing of the proxy statement, approval for listing on Nasdaq, and a minimum of $25 million in cash being available at or before closing. Alternus may waive the minimum cash condition at its discretion. The transaction is expected to close in the first quarter of 2023.

On closing, Clean Earth intends to change its name to Alternus Clean Energy Inc. The combined company will be led by Vincent Browne, chairman and CEO of Alternus, and the business will continue to operate as normal. Clean Earth and Alternus intend to arrange a committed capital on demand equity placement program of up $100 million, which can be called upon at the discretion of the combined company, and potentially other financing options ahead of completion of the business combination.

Alternus shares will continue to trade on the Euronext Growth market in Oslo, while Clean Earth’s common stock is expected to continue to be listed on the Nasdaq Market. Bonds issued by Solis Bond Company DAC will continue to trade as normal. Bondholders of Solis Bond Company DAC will be approached in due course in relation the transaction.

“Alternus has reached an inflection point in our growth, with a significant increase in contracted pipeline and operating assets over the past year,” says Browne. “We are grateful to have support from investors in Europe and the United States who are committed to the clean energy transition. We expect that this proposed transaction will leave Alternus well-positioned and well-capitalized to continue developing and/or acquiring, installing and operating renewable energy assets across Europe and also now in the United States.”

“Alternus has built a strong foundation for rapid growth of its renewable power portfolio, and with their continued expansion we anticipate that Alternus will continue to generate consistent, long-term returns for shareholders,” comments Aaron Ratner, CEO of Clean Earth. “Our business combination, Nasdaq listing, and the anticipated access to new equity and potentially lower cost debt capital is expected to fuel this expansion and accelerate the company’s conversion of development and contracted projects into cash flowing operating assets.”

“The passage of the U.S. Inflation Reduction Act will be a game-changer for the growth of solar power and other renewable energy technologies,” adds Nicholas Parker, executive chairman of Clean Earth. “Likewise in Europe, solar PV capacity is set to grow ~40 percent over the next three years. We believe Alternus is well positioned to take advantage of this once-in-a-generation energy transition.”

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Executves from FirstLight and partner companies marking its first energy storage acquisition back in 2019. Image: FirstLight Power.

Independent Power Producer (IPP) FirstLight Power will replace its Tunnel Jet peaking facility in Connecticut, US with a battery energy storage system by 2024/25.

The Tunnel Jet facility in Preston, southeast Connecticut, is the company’s last fossil fuel generating unit and will be decommissioned in 2023. Construction will begin following procurement and the securing of interconnection and permits, with a target operational date of late 2024 or early 2025.

It will work with renewable energy developer New Leaf Energy to design, manage, and procure the 17MW battery energy storage system (BESS). The BESS will be co-located at the same site as FirstLight’s Tunnel Hyro facility, a 2.1MW run-of-river hydoelectric power facility on the Quinebaug river.

FirstLight and New Leaf will also provide US$60,000 in seed funding to a renewable energy industry training programme for local workers organised by Operation Fuel. Operation Fuel is an emergency energy assistance programme which provides help with utility bills to residents across Connecticut.

Alicia Barton, president and CEO of FirstLight, said: “We are excited to be working with New Leaf Energy to develop a new emissions-free battery energy storage system that will deliver clean, safe, and reliable electricity to meet Connecticut’s growing clean energy needs.”

Dan Berwick, CEO of New Leaf Energy, added: “New Leaf Energy is excited to advance this important project at FirstLight’s Tunnel Jet facility, part of an innovative collaboration that will help create hybrid renewables solutions across New England by combining solar and energy storage resources with existing generation.”

Fossil fuel plants make great locations for renewable energy resources and energy storage thanks to existing grid connections and infrastructure. Other fossil fuel plants in Connecticut may follow in Tunnel Jet’s footsteps after ArcLight, which owns 5GW of thermal plants across the New England state, New York and California, said it sees its portfolio as ideal locations for battery storage projects.

Firstlight entered the battery energy storage market in 2019 when it acquired Advanced Microgrid Solutions (AMS) portfolio of energy storage units, at Brandeis University and the University of Massachusetts at Dartmouth, totalling 1.3MW. AMS was then acquired by Fluence, the largest battery energy storage system in the world, a year later.

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The Ramona Unified School District has eight new electric buses which can provide power to the grid when needed. Image: Nuvve/Ramona Unified School District/PR Newswire.

A trio of projects using electric vehicle (EV) batteries and charging infrastructure to support the grid in California have been announced this week.

The first, in Oakland, will see stored energy from electric buses provide backup power to the West Oakland Branch of the Oakland Public Library, to power its recently-upgraded HVAC and air filtration system, providing clean air and electricity to create a public shelter during emergencies and outages.

Majority-funded by the California Energy Commission (CEC), the US$3.6 million project aims to demonstrate the value of bidirectional EV charging to create a ‘vehicle-to-building (V2B) resilience hub’, the first of its kind.

Partners in the project are the Center for Transportation and the Environment (CTE), The Mobility House, AC Transit, New Flyer, Schneider Electric, the City of Oakland and WOEIP (West Oakland Environmental Indicators Project).

Each electric bus will contribute six hours of backup power to the critical loads at the library while hydrogen fuel cell-electric buses will provide up to 11 continuous hours of backup power.

“Powering emergency shelters with islanded energy supply is an innovative feat we are honored to help facilitate,” said Jana Gerber, president of Microgrids North America at Schneider Electric, a company specialising in digital automation and energy management.

Infrastructure for the project is expected to be installed by the middle of 2023, and demonstration, analysis, evaluation, and knowledge transfer for the pilot programme will last two years thereafter.

Meanwhile in San Diego, eight new electric buses have been unveiled by vehicle-to-grid (V2G) company Nuvve, bus manufacturer Blue Bird Corporation and the Ramona Unified School District. They are powered by Nuvve’s DC fast chargers and its GIVe V2G energy aggregation platform.

The vehicles are qualified to generate revenues for the school district through investor-owned utility (IOU) SDG&E’s Emergency Load Reduction Program (ELRP), by selling energy stored in the batteries back to the grid during times of high grid stress or emergencies. ELRP was launched by the California Public Utilities Commission in October 2021 to allow consumers to reduce usage to help avoid grid outages during peak periods.

The School District will be able to use the buses to receive $2 per kWh as part of the ELRP, equating to up to US$7,200 per bus per year.

“When a V2G interconnection occurs, the bus, charger and grid are essentially talking to each other,” said Gregory Poilasne, founder and CEO of Nuvve. “This communication through our GIVe platform is essential: it monitors the amount of energy being sent to the grid, while ensuring there’s enough energy necessary for drivers to complete their routes the next day.”

Blue Bird and Nuvve’s cooperation started in 2020 and now all of the former’s Type V and Type D electric buses come standard with Nuvve’s V2G integration capabilities. School districts can use Nuvve’s V2G platform to charge the buses when rates are low and sell energy back to the grid when rates are higher, to help offset the upfront costs of the charging infrastructure.

As readers of Energy-Storage.news‘ coverage of developments in the V2G space will know, many projects in the space are using school buses. Larger batteries and more predictable usage schedules make them fertile ground for the technology, while many challenges remain in the consumer EV space.

While the previous two announcements show examples of electric vehicle batteries providing power to the grid, battery-integrated EV charging infrastructure can do the same.

Distributed energy resource (DER) platform company Voltus this week announced it is working with FreeWire Technologies, which manufactures such battery-integrated infrastructure, to provide flexible battery charing load to grids throughout the US.

The initial phase of the collaboration will also be in California. Another IOU, PG&E, will be able to dispatch FreeWire’s infrastructure to provide critical support to grid operator CAISO (California Independent System Operator) to mitigate blackout risk.

“Our partnership with Voltus enables us to provide essential services to the grid, while safeguarding the charging experience for the EV driver,” said Sudhansh Neravetla, director of energy services, FreeWire Technologies. 

“By connecting FreeWire’s charging station to electricity markets, Voltus helps to realize the full financial and sustainability value of EVs and charging stations,” added Dana Guernsey, Voltus chief product officer and co-founder.

California aims to deploy 250,000 public and shared private EV chargers by 2025. Forecasts for 2030 demand indicate around 1.2 million chargers will be needed for light-duty (i.e. consumer) vehicles and 157,000 chargers needed for medium- and heavy-duty vehicles.

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Invinity’s VS3 flow battery units. Image: Invinity Energy Systems.

The California Energy Commission (CEC) has approved funding for a solar-plus-storage microgrid project which will include Invinity Energy Systems’ largest flow battery to date.

The stock exchange-listed Anglo-American flow battery provider announced the CEC’s decision today, which was taken at a commission meeting yesterday. An Invinity 10MWh vanadium redox flow battery (VRFB) will be installed for the community of the Viejas Band of Kumeyaay Indians.

The project is being carried out by Indian Energy, a Native American-owned business working on grid-scale battery storage and microgrid projects, with funding coming from the CEC’s Long-Duration Energy Storage Program.

The energy commission has determined that long-duration energy storage (LDES) will be a necessary component of California meeting its goals of net zero greenhouse gas (GHG) emissions and a fully renewable energy sector by 2040 and has funded various projects along these lines.

In 2020 as the programme opened, the CEC determined that at least 1GW of LDES will be needed on the California Independent System Operator (CAISO) grid.

The commission is also supporting microgrid projects that support community resilience from electricity grid outages. In California, energy supply is sometimes at risk in large swathes of the state, from the direct threat of extreme weather events such as heatwaves, to measures such as Public Safety Power Shutoffs (PSPS) where utilities de-energise power lines to prevent them causing or exacerbating wildfires.

For example, Indian Energy is working on another project which will install and then assess the use of four different types of non-lithium, alternative LDES technology. As reported by this site in January 2021, that includes flow battery, mechanical storage, supercapacitors and zinc hybrid cathode batteries.

Invinity has so far been awarded funding for at least four other California microgrids using its proprietary flow battery tech.

‘Very different tech to what customers are used to’

At last month’s RE+ 2022 solar PV and energy storage industry event which took place in the state, Invinity Energy Systems chief commercial officer Matt Harper told Energy-Storage.news in an interview that the CEC is funding the projects to “really demonstrate the marriage of long-duration storage and microgrid resiliency together”.

“The concept being that each of those things were incredibly well proven. Everyone knew that flow batteries could run a long time, and everyone knew that microgrids tended to work really well. But by combining the two together, their thinking was that you could unlock a set of capabilities that would be really, really useful, especially for comparatively remote locations, and especially in regions where wildfires have become more and more of a challenge,” Harper said.

Harper gave the example of a project for another indigenous community, the Soboba Band of Indians, where an Invinity flow battery will be installed at a fire station, turning the fire station into a emergency hub people can go to if a wildfire hits the area. Day-to-day the battery will enable the fire station to be powered with solar energy stored in its electrolyte tanks.

Invinity has a few partners in California developing projects using the VRFB technology, like Webcor and GRID Alternatives – the latter focusing on bringing clean energy to low income or disadvantaged communities – as well as Indian Energy.

As well as providing the technology, the flow battery company also has a role to play in educating those partners about how to install and use it.

“What we have to do is to educate them about what our product is, how it works, how it goes in… all that kind of stuff, because we are very different from a lithium battery in many ways,” Harper said.

“Everything from the physical size of the system to the ways that you dispatch the battery, to the ways that you need to archive the data that’s coming off the battery itself are very different from what a lot of these developers are used to, even if they have a lot of storage in their portfolio already.”

It’s been a busy last few days for Invinity. As reported by Energy-Storage.news earlier this week, it has just received a customer order for a 1.3MWh system for a data centre in Arizona, US.

Then yesterday, it announced another sale, this time in Belgium to energy and industrial equipment and services company Equans Belux. Four of Invinity’s VS3 flow battery units totalling 0.8MWh will be installed at an Equans facility.

Invinity said that Equans, owned by energy major Engie, will use the project as an “important reference point” to determine its suitability for rolling out to its own customers.

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An advanced compressed air energy storage (A-CAES) plant in Ontario. Image: Hydrostor.

To stay in line with national net zero emissions policy objectives, Canada will need to install somewhere between 8GW and 12GW of energy storage by 2035, according to a new report.

Prepared for trade association Energy Storage Canada by consultancy Power Advisory, the white paper outlines the need for and potential to deploy energy storage in all seven of the country’s provinces.

Canada is targeting net zero emissions by 2050 from all sectors. However according to a government mandate issued in 2021, its electricity sector needs to be 90% non-emitting by 2030 and fully zero emission by 2035.

Power Advisory’s estimated need for storage would be the optimal level to put it on the right track, to achieve those goals, it said.

Ontario, where just a few days ago the government ordered electricity network operator Ontario IESO to administer the procurement of between 1,500MW and 2,500MW of energy storage to come online by 2027, has the largest potential to deploy energy storage at scale, the report found.

As noted in our coverage of that announcement, that’s largely to do with Ontario’s high demand for electricity, which is projected to grow about 1.7% year-on-year for the next two decades.

This is due to its growing population, government support for electrification of buildings and transport, and for attracting and fostering investments in EV and battery manufacturing, and low carbon steel production as well as other industries.

As Power Advisory pointed out in its report, ‘Energy Storage: A Key Pathway to Net Zero’, Ontario also has 10GW of natural gas generation that needs to be repurposed or replaced by 2035.

In a way, Ontario’s status is a proxy for what the entire country needs: new electricity supply resources to support growing demand in tandem with the replacement of existing carbon intensive generation.

The white paper makes reference to a report published in September by the Canadian Energy Regulator, called ‘Canada’s Energy Future’, in which multiple scenarios were modelled for attaining the 2050 target.

Even in a base case scenario, modelled only with regard for four-hour duration battery storage and not including distributed energy resources (DERs), the regulator found a need to deploy at least 1.7GW of storage each year to 2050, for a cumulative 52GW by the target date.

‘Versatility of storage will be essential’

Power Advisory and Energy Storage Canada emphasised the versatility of energy storage, meaning it has an important role to play in each of the provinces, but those systems could perform a range of different applications suited to the needs of each.

For instance, in some of the more rural regions of Canada, energy storage could be a cost-effective alternative to transmission network buildout – that’s something Energy-Storage.news has reported on around a couple of projects in the country.

In the more urbanised areas, with Ontario being the obvious example, using storage’s role to reduce peak demand for energy from the grid will likely be its standout application.

It is important to take into consideration that projections for the future can change and that need for storage may change, perhaps exceeding the 12GW mark by 2035. For instance, some forecasts at national and provincial level find an expectation for 15% to 20% growth in demand for electricity by 2035, while others predict a faster electrification and energy transition process, with a 30% to 40% growth in demand for electricity.

The good news there is that the white papers authors think there may be potential to exceed that upper limit of storage deployments by that time as well, to meet that need.

“Canada has set an ambitious goal to achieve a net zero electricity system by 2035, success of which depends on energy storage,” Energy Storage Canada executive director Justin Rangooni said.

“The versatility of energy storage is going to be absolutely essential to meeting the needs of more-end use electricity, an increasing volume of which will be generated by intermittent renewable and non-emitting resources.”

Energy Storage Canada and Power Advisory have worked together on a number of other reports in the past. A report published in June focused on how Ontario electricity rules and regulations should allow energy storage to be deployed as a non-wires alternative (NWA) to more costly investment in distribution network infrastructure.

Energy Storage Canada hosted the 7th edition of its annual conference this week.

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Strategic Power Projects managing director Paul Carson. Image: Strategic Power Projects.

Ireland’s national planning body An Bord Pleanàla has approved a €140 million (US$135.7 million) proposed battery storage facility set to be developed by Strategic Power Projects at Dunnstown, County Kildare.

The project will have a capacity of over 200MW, making it the single largest battery application in Ireland, the company said.

Strategic Power Projects has been developing its renewable and battery pipeline since partnering with investment firm Gresham House in October 2021. Upon signing the partnership, the two firms committed to develop a solar and storage portfolio with a combined capacity of over 1GW.

The proposed facility situated at Dunnstown makes up part of this agreement. Strategic Power said building work will begin as soon as connection to the grid has been achieved.

“Ireland has made enormous strides over recent years in the development of wind and solar energy, but there needs to be similar action taken to ensure that we have enough energy storage capacity to make efficient use of the renewable energy we produce, and to balance the grid as it takes on more and more renewable energy,” Strategic Power Projects managing director Paul Carson said.

“The Dunnstown facility won’t solve Ireland’s storage problems on its own, but if the positive decision is a sign of things to come, then that is very positive news for the people of Ireland.”

To read the full version of this story, visit Solar Power Portal.

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EnergyAustralia is long-term operator of the 50MWh BESS at the 60MW Gannawarra solar farm in Victoria, using Tesla Powerpacks and developed by Edify Energy and Wirsol. Image: Edify Energy.

Major Australian energy generator-retailer EnergyAustralia is tentatively planning to build a 500MW battery energy storage system (BESS) on land it owns in New South Wales.

The company, said today it is investigating the feasibility of putting a grid-scale battery system with up to half a gigawatt of output at Mount Piper, a 1,400MW black coal-fired power plant in its portfolio.

As with similar projects of its type announced in Australia and around the world, siting the BESS at or adjacent to an existing grid-connected power generation asset will allow for the use of existing infrastructure, such as substations, and overhead wires, reducing the cost of construction and commissioning.

EnergyAustralia said further assessments and consultation with local communities will now go ahead, with the company seeking approval for the Mount Piper BESS through New South Wales’ planning process.

The company expects that if the project successfully goes through that process, it could be up and running by the end of 2026. EnergyAustralia did not give a figure for the expected or likely megawatt-hour capacity of the asset in a press release.

EnergyAustralia, a subsidiary of Hong Kong-headquartered China Light & Power, has a portfolio of energy resources that includes gas peaker plants, coal and a 66MW wind farm as well as two of Australia’s first large-scale battery storage projects, Gannawarra and Ballarat.

Both of those battery projects were completed in 2018 in the state of Victoria, and as reported by Energy-Storage.news, their first year in operation provided important data and proof points of how BESS assets could successfully participate in Australia’s National Electricity Market (NEM).

Other projects the company already has in development include a 350MW, four-hour duration (1,400MWh) in Victoria’s Latrobe Valley. Like Mount Piper, EnergyAustralia has elected to build that project, called Wooreen Energy Storage System, on the site of one of its existing power plants, in that case the company’s gas-fired Jeeralang power plant.

EnergyAustralia revealed its plans for Wooreen in 2021, noting that its addition to the local grid will ease the retirement of Yallourn, another 1,400MW coal power plant. Not only is the generator-retailer (gentailer) targeting carbon neutrality by 2050, but it is also paying hundreds of millions of dollars to maintain and run the Yallourn power station, providing added impetus to take it out of service.

A couple of months ago, the NSW government Department of Planning and Environment gave planning approval to a 500MW/1,000MWh BESS project proposed by developer Greenspot at the site of Wallerang, another EnergyAustralia coal power plant which was retired in 2014.

“The project would support future energy security in New South Wales as coal generation retires and more renewables enter the system,” EnergyAustralia head of portfolio development Daniel Nugent said of the Mount Piper plan.

“The BESS would be a welcome addition to the state’s growing list of big clean energy storage projects. If approved, it will also provide an economic boost to the Central West region and help to transform it into a renewable energy hub.”

As reported by our colleagues over at PV Tech recently, New South Wales is targeting the deployment of 12GW of renewable energy by 2030 as well as 2GW of long-duration energy storage, opening a bi-annual tender process in August.

The state is developing five large Renewable Energy Zone (REZ) multi-technology hubs, attracting strong interest from developers and investors.

In July this year, transmission operator Transgrid said that studies had shown grid-scale battery storage to be its preferred option for ensuring reliable electricity supplies in New South Wales’ regions, choosing from a range of considered options and highlighting potential “billions of dollars” in benefits from doing so.

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