Interestingly, neither project will use vanadium redox flow battery (VRFB) technology, the most common electrochemical flow battery storage tech.

Instead, one project will utilise zinc-bromine flow battery technology developed by Queensland-headquartered company Redflow, while the other will utilise iron and saltwater electrolyte flow battery tech developed by US company ESS Inc, but licensed to Australian company Energy Storage Industries – Asia-Pacific (ESI).

Crucially, both technologies will be locally made, which was a driver for the funding announcement, premier Palaszczuk said.

“If we don’t back investment in batteries in Queensland we will see investment go offshore. Our government is backing local manufacturing of batteries because that means more jobs across more regions in Queensland,” Palaszczuk said.

With each project to receive AU$12 million of government funding, the statement did not give further details about project sizes or applications. However it did reveal that preferred sites have already been identified for each, with Redflow’s in Ipswich, southwest Queensland and ESI’s on the eastern coast in Wide Bay.

The projects will be deployed by state-owned utility Energy Queensland as part of its programme to assess how battery storage can be used to help manage energy costs for consumers.

Zinc-bromine flow battery

Redflow was founded in 2005 and is now onto its third generation device, the ZBM3, which was launched in 2022. The company makes stackable 10kWh units and was known for working largely on rural microgrid and small commercial applications like telecom towers, but earlier this year was awarded a 20MWh project in California, US.

That marked a continued step up into the larger-scale segment as well as the international market which began a year or so before that with the commissioning of a 2MWh project, also in California, CEO Tim Harris told Energy-Storage.news earlier this year.

Harris said Redflow picked its zinc and bromine electrolyte chemistry due to the abundance of both elements, adding that it can also achieve higher energy and power density than vanadium or iron electrolyte flow battery makers can.

Iron flow battery

Last July, Queensland’s state government announced the start of construction at ESI’s factory to make iron electrolyte flow batteries in the city of Maryborough.

ESI said at the time that it picked ESS Inc’s iron and saltwater technology after a four year process of selection, with the factory representing AU$70 million investment. ESS Inc remains the IP holder of the technology, for which ESI is targeting 400MW annual production capacity by 2026.

As much as 80% of the materials and components could also be sourced within Queensland, ESI has said previously, while ESS Inc has claimed the strategic agreement between the two parties could result in 12GWh of deployments.

Like other flow batteries, ESS Inc claims the advantages of its technology include ability to cycle daily without degradation and scale up systems to large capacities and therefore durations of storage.

Why not vanadium?

The Queensland government is already also supporting vanadium flow battery technologies, with perhaps its biggest step being a direct involvement in developing a vanadium electrolyte processing facility in the state.

The Palaszczuk administration has set the state – historically Australia’s most coal-dependent – a target of getting to 70% renewable energy by 2030, and introduced the AU$62 billion Energy and Jobs Plan to support the energy transition.

A paper produced by consultancy Accenture for the state government found that Queensland’s battery industry could create up to AU$1.3 billion in economic activity and over 9,000 jobs by 2030, as well as being ripe for battery storage deployment within the state itself.

Moreover, the report found that while Queensland could have good opportunities for increased involvement in the dominant lithium-ion battery market, it is in the currently more niche flow battery space that the state could hold the most competitive advantages. That includes the fact that around 30% of the world’s vanadium reserves are thought to be in Queensland.

The government recently also gave its support to a VRFB trial project by Vecco Group, another Queensland-headquartered company which has built an electrolyte production facility in the state. Vecco Group ordered a 250kW/750kW (3-hour duration) system from Japanese manufacturer Sumitomo Electric. It will be used to assess how energy storage can be used on the distribution network of Energy Queensland subsidiary Energex.

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SunPower Financial, the in-house financial services institution of SunPower – a residential solar technology and energy services provider – has entered into an agreement in principle with ADT Solar, a division of ADT Inc., to become the exclusive lease and PPA provider for ADT Solar’s customers.

Through this agreement, ADT Solar expects to begin offering customers a lease option for the first time, making solar accessible to more Americans. SunPower Financial will act as the exclusive lessor for ADT Solar customers who choose to finance with a lease or power purchase agreement (PPA).

“We look forward to working together and providing ADT Solar customers with attractive lease and PPA options to make the decision to switch to solar an easy one,” says Jason MacRae, executive vice president of financial products at SunPower.

According to independent research commissioned by SunPower, nearly two in three Americans who would consider solar don’t think they could afford to make the switch. Financial products like leases, PPAs and loans allow qualified customers to adopt renewable energy with no money down by financing their system for up to 25 years. In the future, the two companies expect to explore opportunities to collaborate on additional streamlined solar and smart home services for homeowners.

ADT Solar intends to make products offered by SunPower Financial available to its customers this year.

Image by Freepik.

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Gilad Yavetz

Community-based, not-for-profit public power utility Salt River Project (SRP) and Clenera, an Enlight company, have executed a power purchase agreement for an additional 394 MW AC – or 475 MW DC – of clean energy at CO Bar Solar outside of Flagstaff, Ariz.

This is the second agreement between Clenera, a developer, builder, owner and operator of utility-scale solar farms and energy storage facilities, and SRP at the CO Bar complex. As a result, SRP, the largest electricity provider in the greater Phoenix metropolitan area, has now procured nearly 800 MW AC – 1,000 MW DC – of power from the project.

“This is not only the largest solar plant in Arizona and one of the largest in the United States, but it will also be the most significant solar resource in SRP’s energy portfolio,” says Jim Pratt, CEO of SRP. “SRP will be quadrupling the amount of utility-scale solar on our power system in just the next two years, with CO Bar Solar as a key part of this.”

CO Bar Solar is a 1.2 GW landmark solar and storage complex being developed by Clenera, a subsidiary of Enlight Renewable Energy, a company devoted to utility-scale renewable energy projects. The project, expected to be one of the largest in the U.S., will occupy up to 2,400 acres on Babbitt Ranches private land in Coconino County. Construction on CO Bar Solar is set to begin in the fourth quarter of 2023. It is expected to reach commercial operation in phases throughout 2025.

“We are thrilled to be partnering with SRP again on CO Bar Solar and providing them with reliable, clean energy,” says Gilad Yavetz, CEO of Enlight. “CO Bar represents a strategic project in Arizona, serving as a prime example of our approach to greenfield development that capitalizes on sizable interconnection positions.”

Over the course of the CO Bar Solar construction timeline, approximately 550 construction jobs will be created, with many being local. Once complete, SRP will receive enough power from this resource to meet the needs of approximately 180,000 average-size homes.

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Leeward Renewable Energy (LRE), a renewable energy developer and independent power producer, and Nextracker, a specialist in utility-scale solar tracker and software optimization technology, have signed a volume commitment agreement (VCA) to deliver 3 GW of Nextracker’s NX Horizon smart solar tracking system to LRE solar projects under development and construction through 2027. This is the second VCA agreement between LRE and Nextracker, further extending their strategic partnership.

In conjunction with the agreement, Nextracker will provide its solar tracker and software technology to LRE solar power projects located in strategic areas across the United States. Paired, Nextracker’s TrueCapture and NX Navigator software technologies maximize solar energy production and offer reliability features that help protect solar panels and mitigate the adverse effects of extreme weather, such as snow, hail, and high winds.

Says Jason Allen, LRE CEO: “Nextracker is a domestic supplier with a strong track record of delivering systems on time, and our agreement allows LRE to significantly de-risk our supply chain and uphold our commitment to providing our customers with reliable energy to meet their needs and sustainability goals.”

This alliance emphasizes a shared pledge by both companies to increase domestic job creation and U.S.-made manufacturing of renewable energy projects. Much of the steel and electronics used in the supply of Nextracker’s systems is manufactured in factories the company has commissioned over the past two years, creating several hundred jobs. Nextracker will supply LRE finished steel product from its recently opened domestic steel manufacturing locations in Pennsylvania, Tennessee and Texas as part of this agreement.

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As well as causing strain for the grid, those spikes in energy demand can also result in spikes of high energy prices.

While California has become a world-leading market for large-scale battery energy storage, earlier this year surpassing 5GW of such systems in the CAISO grid service area, it is thought that distributed energy resources (DERs) such as home battery systems can also play a more prominent role in managing supply and demand.

Regular readers of Energy-Storage.news will have seen that last year, following summer heat waves, various behind-the-meter (BTM) battery storage providers said their customers’ systems contributed in this way.

In one instance, residential solar and storage provider Sunrun said it dispatched energy from 80MW of customer systems to the grid during one evening peak in September 2022, while California utility PG&E said energy stored in a fleet of 2,500 Tesla Powerwalls delivered up to 16.5MW of energy during one mid-August event.

VPPs to help avert grid emergencies

Other providers made similar claims, but the big difference is that those dispatches from customer systems were made as part of the CAISO Emergency Load Reduction Program (ELRP). Under the programme, CAISO issues ‘Flex Alerts’ when supply is becoming too constrained to meet demand.

The alerts effectively ask customers to turn down their usage of power from the grid. That proved effective in managing the California energy system, together with the contribution of large-scale batteries and renewable energy as well as other electricity users simply turning down their electricity use.

However, some providers of systems enrolled in the Flex Alert programme said it would be better if that type of demand response was initiated as a regular course of action and not just left to emergency situations.   

What’s different in the latest determination from the California Energy Commission is that Demand Side Grid Support will allow a more systematic approach to using home batteries to help manage the grid.  

Fleets of home battery systems will be aggregated into virtual power plants (VPPs), and dispatched during times of peak demand, helping to respond to and avoid grid emergencies and lowering electricity prices by lowering the cost of operating the grid.

Customers will start being signed up during this year, in some cases during this summer, according to the California Solar and Storage Association (CALSSA), which said the rollout of the programme is a promising start.

CALSSA said California needs to do more to incentivise the use of home batteries as grid resources during peak events. There are already thought to be more than 100,000 home battery storage systems online in the state, representing as much as a gigawatt of energy that could be dispatched to help the grid.

A recent study by consultancy Brattle Group found that VPPs could save utilities across the US between US$15 billion and US$35 billion in the next decade. According to the study, commissioned by tech giant Google, putting about 60GW of DER into VPPs would represent about 40% to 60% of the cost of delivering the same resources from alternative sources.

‘Small step in the right direction’

“Energy needs in the 21st Century demand innovative thinking and that is what the California Energy Commission is embracing today. California must do more to encourage consumers to adopt solar and battery technologies at the local level so that we can keep the lights on and the air clean,” Bernadette de Chiaro, executive director of trade group CALSSA said.

“Today’s vote marks one small step but a step in the right direction nonetheless.”

A few days ago, a consortium working to offer solar PV and energy storage at no cost to low-income California households told Energy-Storage.news that unlocking grid services value through virtual power plants would be the key to financing a wider rollout of clean energy equipment at low cost to customers.

A day before the CEC’s three commissioners voted unanimously to allow battery storage VPPs to join Demand Side Grid Support, utility PG&E announced a DERs tie-in with digital automation and energy management specialist Schneider Electric.

The pair have deployed a distributed energy resources management system (DERMS) onto the Microsoft Azure cloud platform, aimed at enabling more proactive management of the grid through resources like rooftop solar PV, electric vehicles (EVs) and batteries.

Schneider Electric’s EcoStruxure DERMS software platform integrates, analyses and optimises DER data, allowing grid operators to leverage them to provide much-needed flexibility to the network.

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The seven-turbine project was given planning approval by Welsh Ministers in September 2022 under the UK’s Developments of National Significance (DNS) planning process.

Although details of the energy storage system (ESS) such as capacity, technology, provider or use case have not been revealed, its size in MWh is likely to be close to the 25MW headline figure.

Documents for the project including a technical appendix and a site layout both say that eight shipping container-sized ESS units will be deployed, and containerised ESS units of that size typically have an energy storage capacity of a few MWh.

Furthermore, a document from Western Power Distribution showed the project had negligible import capacity in its grid connection approval, meaning it would most likely only be charging from the wind and then discharging to the grid when generation tails off.

John Boyce, Development Director for Wind in the UK&I, said: “We’re really pleased to partner with Marubeni to help deliver Upper Ogmore, a project that will produce clean, secure electricity for thousands of homes.”

“This month the world experienced its three hottest days on record and it is projects like Upper Ogmore that will deliver the practical solutions to climate change, while simultaneously creating cheap electricity and investing millions in the Welsh economy.”

Tomoki Nishino, president & CEO of Marubeni Europower, added: “Marubeni plans to sign an MoU with the UK government which envisages approximately £10 billion of investment in the UK with its partners over the next 10 years. This project would be one of the forefront projects to realise our ambition.”

RES, which claims to be the largest renewables developer in the world, has been active in Wales since the early 1990s and has developed five onshore wind farms in the country.

Marubeni has invested in various parts of the energy storage supply chain. Most recently, it announced a partnership with a local developer to build energy storage projects in Vietnam. In 2021, it invested in California-based second life energy storage firm B2U while in 2019 it invested in a US generated distribution company GridMarket.

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The company raised €24 million in equity investment from Cummins Inc., a US corporation that develops and distributes engines, filtration, and power generation products, 12 months ago, with a total of €30 million investment raised to-date according to Pitchbook.

The guarantee by the European Commission under the EU’s InnovFin Energy Demonstration Projects (EDP) Facility most likely allowed VoltStorage to get a bigger loan than would otherwise have been possible, with venture debt not typically exceeding the most recent equity round.

The EIB said flow battery technology has the potential to “become a game changer for the green transition towards renewable energies,” which is why it got a guarantee under the EDP Facility.

Flow battery technology contains fewer scarce metals like lithium, cobalt and nickel, has a much lower fire risk and next-to-no degradation when compared with lithium-ion, making it, in the eyes of many, a much better choice for stationary energy storage system (ESS) technology, especially at longer durations for heavy-cycling applications.

However, it has a much lower energy density meaning a larger land footprint, a higher upfront capital expenditure investment required, lower round-trip efficiency (RTE) and also a much more limited supply chain today making utility-scale projects at the larger end harder to deliver.

VoltStorage aims to bring its technology to utility-scale from 2025 onwards. The company has changed strategy since inception in 2016, when it was initially targeting the residential energy storage market. Since then, it has pivoted to focus on the commercial and industrial (C&I) and grid-scale spaces.

EIB Vice-President Ambroise Fayolle said: “The EIB supports innovative and sustainable advanced technology developed and manufactured in the European Union, and especially storage technology. VoltStorage’s technology has the potential to become a game changer for renewable energies, making them as reliable 24/7 as fossil fuel power plants have been in the past. We are therefore proud to support this promising start-up.”

Jakob Bitner, CEO & Co-Founder of VoltStorage, added: “This financing will enable us to fully focus on developing and commercialising our innovative energy storage solutions, as well as scaling up our production capabilities to meet growing demand.”

Other DACH-based (Germany, Austria, Switzerland) flow battery companies include VRFB firm CellCube and organic flow battery company CMBlu. However, one source told Energy-Storage.news last year that the German market “does not think it needs flow batteries”, with most believing lithium-ion can do short duration and green hydrogen will suffice for anything longer.

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The NYSE-listed company recorded revenues of US$327.1 million, and adjusted EBITDA of US$37.4 million for the quarter. Its project backlog across all technologies grew by 9% sequentially, with US$493 million of new awards.

That included the recent award of a 379MWh battery energy storage system (BESS) portfolio for co-location at four natural gas plants in California with independent power producer (IPP) Middle River Power, and a 313MWh deal in Colorado with electric cooperative United Power.

Battery storage is seeing “tremendous growth”, Ameresco CEO George Sakellaridis said, pushed forward by drivers like the need for resiliency and integration of variable renewable energy (VRE) to the grid.

In the US, the Inflation Reduction Act (IRA) and its package of incentives for clean energy has also offered financial benefits, most notably a new 30% investment tax credit (ITC) for standalone energy storage alongside existing ITCs for standalone solar PV and solar-plus-storage.

Indeed, while solar PV comprises the biggest share (66%) of Ameresco’s 426MWe of energy assets in operation, battery storage at 41% represents the biggest portion of the company’s in-development pipeline.

While most of Ameresco’s battery storage activities to date have been as a contractor installing BESS technology, such as on a 2.1GWh, three-project portfolio for California utility SCE currently nearing the end of construction, the company is seeking to own some battery storage projects.

In an earnings call to explain results, analyst Christopher Souther with B. Riley asked about the status of the recently won deals, to which CEO Sakellaridis clarified that for United Power in Colorado, Ameresco will own the asset, whereas for Middle River Power, Ameresco will serve as a project contractor.

Sakellaridis said construction would probably start on the Middle River Power project within the next “couple of months,” while the United Power asset is at a “pretty advanced” stage of development.

‘The fewer merchant revenue streams the better’ for Ameresco

On the strategy of owning BESS assets, analyst Eric Stine at Craig-Hallum Capital Group asked what the “ideal project” would be, given that energy storage assets have different value streams to other assets Ameresco might own, such as thermal or renewable generation.

As we often hear at Energy-Storage.news, energy storage can deliver multiple functions to grid and customers, meaning that in some markets it is possible to stack revenues from different streams. Analyst Stine asked if Ameresco could offer any clarity on how it saw the business model of selling different services with stored energy, versus selling power from a gas or renewable asset.

“We like capacity contracts,” Ameresco senior VP and chief financial officer (CFO) Doran Hole said.

“The fewer merchant revenue streams the better for us. We like the fixed capacity contracts, and if we can make the numbers work by virtue of looking at CapEx, looking at transportation, implementation, [the] speed with which we can get these things underway with a capacity contract, that’s a better looking thing for us,” Hole said.

According to the CFO, the fact that battery manufacturers now offer long-term service agreements (LTSAs) to manage degradation and/or augmentation of battery cells also helps keep Ameresco “comfortable” with long-term fixed capacity contracts.

Sakellaridis added that the financial return is obviously crucial, with Hole clarifying that size of the project is not as important as the metrics proving a long-term business case.

As well as the US, Ameresco is active internationally in the energy storage space, having been revealed as a consortium partner to a winning large-scale BESS project in Canada’s biggest energy storage procurement, earlier this year in Ontario.

As recently heard from our coverage of a supply chain discussion panel at Energy Storage Summit Asia 2023, project developers are having to be more agile in sourcing supply constrained components. Mahdi Behrangrad of Japanese developer Pacifico Energy said his company speaks to multiple battery cell vendors, including Tier 2 as well as Tier 1 providers.

Doran Hole said it was a similar situation for Ameresco, which is “continuing to expand our number of relationships with battery suppliers,” in a market that remains “fragmented”.

When it came to selecting contractors for the company’s biggest BESS project so far, with SCE, a big influence in Ameresco’s competitive procurement was finding partners that could work with an expedited timeline demanded by contracts with the utility.

As regular readers will know, the pandemic and its knock-on effects delayed the project considerably, but the developer has been able to negotiate on terms with its customer, invoking a force majeure clause a few months ago.

Ameresco will continue to run competitive procurements for suppliers and partners on “nearly all” projects in its pipeline, Hole said, while the company is “heavily involved” in the process of choosing battery suppliers together with its system integrators, such as FlexGen, which is working on the SCE portfolio.

Conference call transcript by Seeking Alpha.

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The office of the Minister for Planning and Public Spaces, Paul Scully, signed off on the decision by the New South Wales director of energy assessments last week on 28 July.

The power plant would be built near Bungendore, a town in the Queanbeyan region of New South Wales (NSW), and has a planned solar generation capacity of up to 350MWac, with 300MW/600MWh of battery energy storage.  

It will be placed at an important strategic location, connecting to the transmission network via an existing 330kV line between the important load centres of Sydney, Canberra and the Snowy Mountains Hydro-electric scheme (Snowy Hydro), according to the website of Octopus Australia’s parent company Octopus Investments.

Blind Creek Solar Farm has been determined as a state significant development (SSD), designed to streamline the process of developing major projects over a certain size, capital cost, or sited in an environmentally sensitive area.

The development was approved after it was found that the project would provide a range of benefits for the local region, from adding low carbon generation capacity to the grid, to reducing reliance on and aiding the retirement of fossil fuel-based coal an gas generation, to creating jobs and adding diversity to the local economy, and creating an expected AU$554 million (US$370.9 million) in investment.

The farmers that launched Blind Creek want to maintain the region’s agricultural traditions, and plan to co-locate sheep farming with the power plant. Short periods of intensive grazing of grass-fed lambs will be rotated, while spacing apart of PV panels will allow access to tractors.

The site will also support a carbon sequestration project, as well as biodiversity and landscape restoration initiatives, according to Octopus. Project partners will also create a Community Benefit Sharing Scheme (CBSS) worth AU$330 per MW each year, for the local community.  

CEFC and Octopus Australia announced their partnership on the project in March 2022, as reported by Energy-Storage.news. It came soon after the pair announced it would be working together on a project to replace the Yallourn coal power plant in Victoria with a 1.5GW renewable energy hub.

“…from the outset our goal was to co-locate renewable energy with regenerative agriculture and carbon sequestration while maintaining sheep production,” project founder and landowner Dominic Osborne said.

Read further coverage of agrivoltaics technologies and projects on our sister site PV Tech.

Agrivoltaics was the subject of the cover story in Volume 34 of our quarterly journal, PV Tech Power, published in Q1 2023. Subscribers to Energy-Storage.news Premium get full access to all editions of PV Tech Power.

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Raj Soi

Babcock & Wilcox Solar Energy Inc. – a subsidiary of Akron, Ohio-based Babcock & Wilcox Enterprises Inc. – has been awarded contracts totaling more than $20 million by Summit Ridge Energy LLC for the engineering, procurement and construction (EPC) of 25 MW of community solar energy projects in Illinois.

B&W has successfully executed multiple projects for Summit Ridge Energy, including a $15 million community solar project announced in March 2023 and a $20 million project announced in 2022.

B&W will engineer, procure and construct the six photovoltaic solar projects, with completion scheduled for 2024.

“As Summit Ridge Energy continues to expand our solar leadership in Illinois, we’re pleased to partner with B&W on another EPC contract,” says Raj Soi, executive vice president of operations, Summit Ridge Energy. “We are proud of our work to create new jobs in Illinois, invest in the local economy and provide solar power savings to more than 20,000 households and businesses.”

With more than 100 solar projects installed, B&W offers reliable system design, construction and optimized system integration. B&W is committed to providing forward-thinking solar solutions, outstanding service, and quality construction with safety as a top priority.

Summit Ridge Energy is the largest commercial solar developer and owner-operator in Illinois, with an energy portfolio of more than 250 MW across the state. Summit Ridge Energy has invested over $900 million in Illinois through the development and acquisition of 116 individual solar farms, located across 35 counties. These projects have employed more than 3,500 construction workers and provide solar power savings to more than 20,000 Illinois ratepayers.

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