MidAmerican’s five coal plants make it the single biggest carbon polluter in the state, the groups said. Image: Emma Colman, Sierra Club.

US utility company MidAmerican’s plan to continue burning coal at five Iowa power plants will be environmentally harmful and more costly than choosing low-carbon alternatives.

That was the core of joint testimony from a coalition of environmental groups, which made a damning assessment of the utility’s latest plans to add significant renewable energy capacity but keep its coal-fired plants running.

MidAmerican Energy Company, serving around two-thirds of Iowa as well as parts of Illinois, South Dakota and Nebraska, has put before the regulatory Iowa Utilities Board its plan, called Wind PRIME.

Through Wind PRIME, MidAmerican would add 2,042MW of wind and 50MW of solar PV to its portfolio but hold fast to its coal as well. According to the utility company, in 2021, its generation capacity was 62% wind, 23% coal, 11% natural gas and 4% nuclear or other sources.

Earlier this week, Midwestern non-profit Environment Law & Policy Center, Iowa Environmental Council and advocacy group The Sierra Club filed a joint testimony with the Iowa Utilities Board.

The groups accused MidAmerican of failing to justify its Wind PRIME plans and noted that the utility’s own analysis of its benefits “relies on MidAmerican’s ageing coal resources for capacity, overlooking the significant costs that could be avoided by transitioning away from those resources and replacing them with alternatives”.

MidAmerican’s coal plants make it Iowa’s biggest carbon polluter, the groups pointed out. They noted that quantitative modelling was not used to determine the Wind PRIME resource mix. Instead, MidAmerican chose its preferred mix based on a combination of options that would earn the highest market revenues or federal tax credits.

Utility’s approach ‘not reasonable’

Instead, a portfolio balancing battery storage and solar PV with a lesser amount of wind, coupled with the retirement of the five coal power stations by 2035 could deliver US$120 million in cost savings versus Wind PRIME, according to analysis by Synapse Energy Economics and Energy Futures Group.

It would also result in 25 million tonnes less of carbon emissions. Commissioned by the coalition of environmental organisations, the analysis found it would be much better for MidAmerican to pick a more diverse resource mix than relying almost exclusively on coal and wind.

“Diversified clean energy, coupled with storage and a robust transmission system, can provide all of our energy needs in Iowa and at a lower cost,” Iowa Environmental Council programme director Kerri Johansen said.

“The status quo has led to escalating uncertainty around extreme weather, high fuel costs, and fears of energy shortages. This is not an acceptable future.”

Johansen urged instead that MidAmerican plan and invest in a “100% clean system,” to “take steps now to study upgrades to the transmission system and to start development of adequate battery storage and solar”.

Devi Glick of Synapse commented that while the modelling approach taken by the utility “might be reasonable for a merchant utility,” selecting its resource mix based on maximised energy revenues and federal tax credits was “not a reasonable approach for a rate-regulated utility with captive ratepayers,” and would keep coal plants running for another 20 years.

Under Synapse’s modelling, on a platform that has been used already in 17 other US states to determine lowest-cost electricity portfolios, it was found that only about a third of the 2GW+ of wind proposed by MidAmerican would actually be required.

Instead, the utility should add 1,600MW of battery storage by 2030, 3,700MW of solar PV by 2035 – including the proposed 50MW project already in the plan – along with around 700MW of wind power. Three of its five coal plants are uneconomic and should be retired immediately, and the remaining two by 2035, according to Synapse’s modelled outcome.  

Numerous other Iowan groups have stepped forward to endorse the group’s advocacy and joint testimony, some of which pointed out various other negative impacts of coal pollution, such as Iowa’s high rates of childhood asthma.

Despite MidAmerican’s continued reliance on coal, according to figures published by the American Clean Power Association towards the start of this year, Iowa ranked third among US states in 2021 for installed clean energy capacity with 12.3GW, behind only Texas (45.1GW) and California (22.9GW).

“Planning to eliminate these expensive, dirty sources of generation and replacing them with renewables made sense even before the benefits of the Inflation Reduction Act were available,” Environmental Law & Policy Center senior attorney Josh Mandelbaum said.

“It is critical that MidAmerican plan for a clean energy transition in a transparent manner using industry best practices before investing billions of dollars of Iowans’ hard-earned money.”

The groups’ joint testimony before the Iowa Utilities Board can be found here.

Energy-Storage.news’ publisher Solar Media will host the 5th Energy Storage Summit USA, 28-29 March 2023 in Austin, Texas. Featuring a packed programme of panels, presentations and fireside chats from industry leaders focusing on accelerating the market for energy storage across the country. For more information, go to the website.

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PV Tech proudly presents this Tech Talk webinar in conjunction with Energy-Storage.news, Sungrow ESS: Technology to stabilise the grid.

In this webinar, we explore how liquid-cooled battery energy storage systems can improve project economics and extend equipment life. The world’s industries are adjusting to life after the COVID pandemic.

At the same time, the world’s energy systems continue moving to higher shares of renewable energy. Energy storage can help grids integrate renewable energy and meet rising demand for electricity, reducing volatility in electricity supply and pricing.

However, large utility-scale battery storage plants face numerous challenges including high capital cost, low energy output, low flexibility, and safety issues.

New technologies can drive the best economics for a battery storage project. For instance, advanced liquid cooling can dissipate heat more evenly from battery cells, with lower auxiliary power consumption, than HVAC systems.

Speaker in this webinar:

Zhendong Qin, senior manager, battery storage system solutions Europe, Sungrow.

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This webinar will also be available on-demand at PV Tech. On-demand registrants will receive presentation slide deck. Check the site here for more info.

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Image: NRG Services.

The 100MW/150MWh Wandoan South BESS project is the largest grid-scale battery storage project in Queensland, Australia. That in itself is significant of course, but it isn’t just the scale of the project that’s notable. Its commissioning, announced in August, came amid a series of serious challenges, writes Joel Bunter, project manager for electrical contractor NRG Services.

Logistical challenges including a skilled labour supply shortage, the Suez Canal blockage, Covid-19, downturns in global manufacturing and extreme weather could not stop NRG Services in delivering one of the largest grid-scale battery storage projects in Australia, on time.

The battery energy storage system (BESS), a joint project between Vena Energy, Doosan GridTech and NRG Services, was also the first large-scale battery installed within the state of Queensland.

The BESS was constructed in Wandoan South in the Surat Basin, 340km north-west of Brisbane in a tight, 10-month timeframe despite numerous logistical challenges.

The AUD$120 million (US$81 million) project was recently commissioned and can store up to 150MWh of energy—enough to power about 57,000 average homes each year.

The 50-strong site team in Wandoan was tested by environmental factors such as strong winds, temperatures ranging from a blistering 40°C (104°F) in summer to -2°C in winter and heavy rain.

Extreme weather was only part of the challenge in delivering Queensland’s largest BESS. Covid-19 meant supply chains were painfully slow, with components manufactured in Spain, the USA, Malaysia and the Philippines held up by lockdowns.

The Suez Canal blockage only compounded this, with the delivery of many of the project’s vital components delayed.

However, the project team worked through these challenges to deliver the project on time and with zero lost time injuries.

The team overcame the logistical and weather challenges by remaining flexible.

By restructuring the program, we were able to effectively deliver the project. We flipped the program while waiting for the necessary battery components.

We had to refocus our priorities when we discovered the majority of battery components would be delayed.

The expected delivery date for the components was late March, but was pushed back to May, so we brought forward different tasks which required a greater workforce much earlier in the programme.

Aerial view of the Wandoan South BESS. Image: Vena Energy.

Samsung battery racks inside the BESS. Image: NRG Services.

‘Crucial role’ in resolving energy intermittency

Fortunately, even though we were in the midst of the second and then third COVID-19 wave, we had access to a skilled team from NRG Services, with the shortfall made up from a local labour hire company.

The labour hire was comprised of skilled international workers living in Australia and hailing from the UK, Spain and South America.

It was very much a global team which was great, providing a real cultural exchange on site.

Supervision and communication became vitally important on site.

We had to engineer solutions which involved using mechanical aids to maximise our available labour. The project threw up a lot of challenges but with some teamwork, using available machinery and careful planning, we were able to deliver the project.

The Wandoan South BESS project will help support Australia’s green energy targets, which were significantly brought forward, following the recent change in government.

After recent power outages in Queensland, the BESS will also create grid stability and deliver stable, more sustainable green energy future for Queensland, Australia’s second largest state.

Testament to its success, Wandoan South BESS has been recognised independently, including winning Battery Storage Deal of the Year at the annual The Asset Triple A Infrastructure Awards and was shortlisted as a finalist for the 2022 Clean Energy Council’s Innovation Awards.

The Wandoan BESS is comprised of 21,896 individual Samsung M3 battery modules in 816 Samsung dual rack frames. The project required 11km of Instrument cabling which the team meticulously slaid, in addition to security, fire detection and gas suppression systems.

Wandoan BESS is one of Australia’s largest DuctSox installations with a 1.8MW battery cooling system and integration of the site’s weather station.

“The Wandoan South Battery Energy Storage System will play a crucial role in resolving the intermittency of renewable energy and enable us to accelerate the energy transition in Australia. We look forward to the support of our partners, as well as the host communities as we continue to contribute to a more sustainable future,” says Duncan Mortimer, Executive General Manager, Vena Energy Australia.

Wandoan South BESS – fast facts:

AUD$120 million (US$81 million) project

100MW output, 150MWh energy

First large-scale battery installed in Queensland

Project team of 50, with 35 from NRG Services and 15 from a labour hire company

10-month project timeline spanning two COVID-19 waves

Located in Wandoan in the Surat Basin, 340km north-west of Brisbane, Queensland, Australia

21,896 Samsung M3 battery modules in 816Samsung dual rack frames

11km Instrument cable installed

One of Australia’s largest DuctSox installations with a 1.8MW battery cooling system

The project was delivered by NRG Services in conjunction with Vena Energy and Doosan GridTech.

About the Author

Joel Bunter is an experienced Project Manager and a senior member of the NRG Services team. He holds qualifications in project management with an electrical and communications trade services background. Joel has 12 years within the industry.

Energy-Storage.news’ publisher Solar Media will host the 1st Energy Storage Summit Asia, 11-12 July 2023 in Singapore. The event will help give clarity on this nascent, yet quickly growing market, bringing together a community of credible independent generators, policymakers, banks, funds, off-takers and technology providers. For more information, go to the website.

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CellCube is the trading name of Enerox, headquartered in Vienna, Austria. Image: Enerox/Cellcube.

Flow battery maker CellCube and energy storage developer North Harbour Clean Energy are in talks to build factory in Australia with 1GW/8GWh annual production capacity.

CellCube, headquartered in Europe, said today that it has signed a strategic cooperation agreement with North Harbour Clean Energy (NHCE) for the construction of an assembly and manufacturing line of vanadium redox flow batteries (VRFB) in the Australian east.

The partners want to target opportunities for long-duration energy storage (LDES) assets like flow batteries to participate in the Australian National Electricity Market (NEM).

As the transition to renewable energy accelerates, there is projected to be a growing need for energy storage in the NEM to fill in gaps when the sun or wind aren’t shining or blowing and meet peaks in energy demand which don’t match up with those generation profiles.

The Australian Energy Market Operator (AEMO), which oversees the NEM said in June that by 2050, that need will total about 46GW/640GWh.

That strongly suggests technologies that offer several hours of storage duration or more will need to be prominent in that mix, alongside plenty of lithium-ion batteries and other technologies that will be more in the >1-4 hour duration range.  

NHCE founder and managing director Tony Schultz said today that the pair will review and select a site to deliver production capacity “of at least 40MW/160MWh” and with a longer-term target of 1,000MWh/8,000MWh per year. However, Schultz did not put a timeframe on those aspirations

Initially, CellCube and NHCE will turn their focus to co-developing what would be Australia’s biggest VRFB project to date. Based on CellCube’s proprietary technology, that would be a 4MW/16MWh system.

In terms of their manufacturing ambitions, what comes next is a feasibility study and other work towards a Final Investment Decision on what would be a 50:50 owned joint venture (JV).

Homecoming for vanadium flow battery

In July, NHCE got backing from a major Australian institutional investor. Superannuation fund Aware Super, which manages around A$155 billion (US$104.67 billion) of customers’ savings, invested in the company. NHCE itself is a new company aiming to develop, own and operate long-duration storage assets in the form of pumped hydro energy storage (PHES) and flow batteries.

That followed a deal signed by NHCE in May with Australian Vanadium, a startup looking to establish a vertically integrated flow battery business in the country from extraction and processing upwards.  

Australian Vanadium “hopes to be in a position to supply vanadium electrolyte” for CellCube-NHCE’s first 16MWh project and subsequent projects, a source close to the company told Energy-Storage.news today. Australian Vanadium currently seeks financing for a vanadium pentoxide (V2O5) electrolyte plant.

The homecoming of sorts continues for vanadium flow batteries, which were invented in Australia at the University of New South Wales in the early 1980s but have only really kicked further into commercial development in recent years as initial patents expired and the need for LDES options becomes more apparent.

The largest project announced in the country to date has been an 2MW/8MWh system in Yadlamalka, a rural part of South Australia. Anglo-American VRFB company Invinity Energy Systems was picked to supply equipment to that project, which was announced in late 2020 and is being part-funded by the Australian government.

Flow battery technology of a different kind may also be produced in the country within a few years. US company ESS Inc has licensed its proprietary long-duration battery technology, which uses and electrolyte based on iron rather than vanadium, to Energy Storage Industries Asia-Pacific (ESI), an Australian company that wants to manufacture and sell the systems in the Asia-Pacific region.

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Another Nexamp project, Newfield Solar in Newfield, NY

Hawaiian Electric has selected seven solar projects on Oahu, Hawaii Island and Maui to be the first on each island to offer the shared solar program (also known as community-based renewable energy or CBRE) to help lower the electric bills of customers who meet low- and moderate-income (LMI) levels and are unable to install privately-owned rooftop solar.

A competitive bidding evaluation process, which accounted for the cost of the projects as well as non-price factors including community outreach, was used to evaluate the proposals. On Oahu, the 6 MW Kaukonahua Solar shared solar LMI project co-developed by Nexamp Solar and Melink Solar Development was selected.

On Hawaii Island and Maui, three projects on each island were selected, all of which are being developed by Nexamp Solar. Next, Hawaiian Electric will work with the selected developers to finalize the 20-year contracts. On Maui, there will be solar+battery storage projects with Lipoa Solar (3 MW), Makawao Solar (2.5 MW) and Piiholo Road Solar (2.5 MW). On Hawaii Island, the solar+storage projects are with Kalaoa Solar A        (3 MW), Kalaoa Solar B (3 MW) and Naalehu Solar (3 MW).

Once the projects are available on Hawaiian Electric’s CBRE Portal, LMI customers – including those who are renters and apartment residents – may become “subscribers” to a facility on their respective island. Once the projects are built and online, the subscribers receive credits on their monthly electricity bill based on their level of participation in the following projects:

In March 2022, the request for proposals was opened for developers, companies, organizations or groups to become a “subscriber organization” of shared solar projects for LMI customers. The LMI shared solar projects are expected to be online in 2025.

“Our proven track record as a long-term owner/operator has made us a trusted partner in hundreds of communities today and our seven new Nexamp projects in Hawaii will help the state move toward its decarbonization goals,” says Zaid Ashai, CEO of Nexamp. “Dedicated to low- and moderate-income residents, each of these shared solar projects will ensure equal access to participate and lower their electric costs while reducing the islands’ fossil fuel dependence. We look forward to making our popular community solar program and other consumer decarbonization services available to all residents of Hawaii in the years ahead.”

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Image: Swell Energy.

Swell Energy has raised US$120 million funding from investors including Softbank Vision Fund 2 towards its 600MWh virtual power plant (VPP) programme across the US.

The company specialises in recruiting home solar PV, battery storage and electric vehicle (EV) customers’ resources into its VPPs. That means aggregating dozens or even hundreds of residential systems to form a single resource that can provide peaking capacity to utilities or grid services in wholesale markets.

Customers benefit by getting a regular payment for allowing the utility to use their home energy equipment. Swell Energy seeks out regions with particular stresses on the local grid that their virtual power plant could solve and balances that against the attractiveness of the market in terms of incentives and supportive policy.

That proposition is underpinned by GridAmp, a distributed energy resources (DERs) management software platform the company unveiled in February as it embarked on an 80MW VPP programme with Hawaiian Electric.

Its other projects include working with California utility Southern California Edison (SCE) and Con Edison in New York.

It has also been involved in market-seeding activities with all three of California’s main investor-owned utilities, signed a 45MWh deal with a community energy group in the state and struck a deal with bank CIT for financing of California projects in August.    

Swell Energy said this week that the fresh investment from a Series B funding round will accelerate its rollout of 26,000 customer energy storage systems for integration in its total 600MWh portfolio. The funding brings its equity capitalisation raised to date to US$152 million.

Schematic of how the VPP works. Image: Swell Energy.

In a 2021 interview with Energy-Storage.news, at which time the company had already amassed 300MWh of contracts across various territories, CEO Suleman Khan said Swell had been working since 2015 to productise the VPP offering.

Khan said the company approaches utilities with analysis of how the Swell proposition can benefit them in delivering reliable energy to their customers and effectively reducing the cost of managing a network with growing shares of renewable energy.

Khan said he brought experience of working in structured finance for solar leasing to the young company. While customer acquisition costs have been the Achilles Heel of the VPP sector, the fact that Swell Energy works directly with utilities brings lists of potential customers to approach could help it overcome that stumbling block.

Technology-focused investment fund Softbank Vision Fund 2 was the lead investor in the Series B, along with Greenbacker Development Opportunities Fund I, which provides growth capital for renewable energy and sustainable infrastructure projects.

Also joining the round were one of alternative investment manager Ares’ Ares Infrastructure Opportunities funds and institutional investor Ontario Power Generation Pension Fund.

“By coordinating distributed energy resources across the grid to intelligently meet fluctuating demand, Swell’s AI- and machine learning-driven platform helps address a major challenge of the energy transition, while also lowering customers’ bills,” Softbank Group director Ben Parton said.

“Utilities and investors have understood the importance of virtual power plants for some time now; this funding further signals that the capital markets see tremendous value in this new asset class,” Swell Energy CEO Suleman Khan said.

Energy-Storage.news’ publisher Solar Media will host the 5th Energy Storage Summit USA, 28-29 March 2023 in Austin, Texas. Featuring a packed programme of panels, presentations and fireside chats from industry leaders focusing on accelerating the market for energy storage across the country. For more information, go to the website.

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The firm provides turnkey solutions for school bus electrification, with V2G as an add-on. Image: Highland Electric Fleets.

We catch up with Sean Leach, director of technology and platform management for Highland Electric Fleets about how vehicle-to-grid (V2G) fits into the company’s strategy.

Energy-Storage.news: Can you introduce Highland to our readers?

Sean leach: Highland Electric provides turnkey school bus fleet electrification, so we approach school districts, cities, towns, school bus contractors, whoever owns and operates the fleets, and we can electrify their school bus fleet, and ideally turn it into one annual mileage based payment, that would be the same or less than what they would pay for a diesel bus.

And in that payment, they get an electric school bus, all the infrastructure that’s required, all the energy that is required to fuel the buses, all the training required for their drivers and their mechanics, and we reimburse for maintenance. And we wrap it all in our software that controls everything and gives them a view of their entire operation.

Why school buses?

The reason we’re so focused on school buses is because their lives are very predictable day to day, they tend to run the same schedule five days a week, twice a day, and as a result of that, they’re frankly a bit under-utilised. Especially when you look at the difference between a diesel bus and an electric bus. The diesel bus moves people twice a day, results in emissions, and then it rots for its entire life just sitting most of the time.

The electric school bus does the diesel bus’ job better and cleaner and then in all the other hours that the bus is sitting there it can be utilised as an energy asset. And because its life is so predictable and because of the grid’s need for power, especially in the summertime, when the buses are literally doing nothing, it represents this perfect storm of taking an asset and using it for its normal thing and then all the other time it’s available to use for other things.

So how does V2G fit into what you do?

The money that can be made from vehicle-to-grid (V2G) services can go back into the contract with the customer to keep that price down.

Though, not every utility is necessarily ready for V2G at this moment in time. We’re working with a lot of them to try and get them on board with it in the most lucrative V2G markets like here in the Northeast where they have some programmes available that we’re already actively participating in and have been for two years.

Here, V2G can contribute a significant amount of money to the school bus electrification projects, but it certainly does not net it out. It does help to keep that contract price down over the 5-10-15 years that contract runs for.

How do you factor it into your commercial contracts?

In terms of how we structure and how we sell it to the customer, we really start by asking: how do we make all of the project economics and the total cost of ownership work for the customer, without V2G?

But if we find out the local utility does have a programme to utilise V2G, we will model that in early on. And we will go to the customer pretty early in the process and say ‘Hey, priority one for your vehicles and charging infrastructure is to move kids twice a day safely. That’s job one. But Highland will also make sure that we can take part in these V2G programmes without impacting your daily operations. And all the money that’s generated from that will go back into your contract to keep it down and get to that price they need the contract to be at.’

But for the customers themselves, they don’t need to manage it, they don’t have to think about it. As long as the buses are back and plugged in by the required time, we will take care of the rest of it through our software. So we really try and make it as painless as possible for the customer. And that they can just focus on doing their job, because they have a hard enough job moving kids twice a day.

How does it affect the contract price?

In terms of how the contracts typically work, from the first day they’re budget neutral. If V2G is something in their market that we can use, we’ll make sure that’s part of it from the first day so that its revenues will offset that higher cost of the V2G infrastructure, like the hardware, the charging equipment etc.

So from the customer standpoint, they’re budget neutral from the beginning, they don’t have to worry about that.

There are some contracts that we might start with a customer where V2G programmes may not be ready at the moment of launch, and we can then build that into the model afterwards. When we do get that up online, we can work that into the contract and make sure that it’s included in the price.

Do school bus operators turn down the offer of V2G?

I don’t think we’ve had anyone who has said no to V2G services if it’s an option in the contract. They all seem pretty open to it. Their basic standpoint is that as long as the buses can do their routes, you guys can do what you want with the buses in the hours after that.

Tell us about a typical electric school bus’ day and how V2G fits into that?

So a typical school bus’ day starts around 6am and then they’re back at the school at 8am or 9am. Once they’re back, they probably don’t even need to charge as there’s plenty of energy left for the afternoon run.

If there are no V2G events in the middle of the day then they may not need to plug in at all. Then they go back out and are back around 4 pm.

When the vehicles are back they plug back in and our platform will look at the site requirements, if there are any time of use rates, demand charges etc, and it will appropriately start charging the vehicles at the right time. We tend to recharge overnight as it’s better for the grid even if there are no charges then.

In the summer the buses are doing morning routes if anything at all. The bus will come back early-to-late morning and plug back in ready for the 4-5pm grid discharge event.

See previous Energy-Storage.news’ coverage of developments in the V2G sector here.

Energy-Storage.news’ publisher Solar Media will host the 5th Energy Storage Summit USA, 28-29 March 2023 in Austin, Texas. Featuring a packed programme of panels, presentations and fireside chats from industry leaders focusing on accelerating the market for energy storage across the country. For more information, go to the website.

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May 2021 inauguration of Ukraine’s first 1MW BESS. Image: DTEK.

The World Bank is financing a tender to equip state-owned hydroelectric power plants in Ukraine with battery energy storage systems (BESS), amid reports of massive damage to the country’s grid and generation fleet.

New utility-scale BESS would be built at existing run-of-river and pumped hydro energy storage (PHES) plants owned by Ukhydrenergo (UHE), to help provide fast and efficient frequency response ancillary services to Ukraine’s grid, or Integrated Power System (IPS).

The hybridised energy assets would be jointly managed by merging new energy management system (EMS) technology with the hydropower plants’ existing SCADA platforms.  

A request for proposals (RFP) has been issued for the project in September, with a deadline for receipt of technical proposals on 30 November and financial proposals on 15 December.  

According to RFP documents produced by US engineering services group Tetra Tech, 197MW of “high power and fast discharge BESS” would be installed in combination with 35.9MWp of solar PV. The solar would provide backup power during low water conditions and serve auxiliary power systems during normal operation.

Those power and energy resources would be deployed at four hydroelectric facilities, chosen for their strategic importance in regions including Kyiv along the Dnipro River which is the backbone of Ukraine’s hydroelectric generation.

In addition to those four sites, the tender envisages the deployment of a further 15MW of energy storage, this time long-duration energy storage (LDES), along with 28MWp of solar PV at another hydropower site in Dniester. This new storage and solar would be used for electric vehicle (EV) charging infrastructure, in addition to serving UHE’s hydropower needs.

The World Bank is supporting the project with debt financing to UHE via the International Bank for Reconstruction and Development (IBRD) and Clean Technology Fund (CTF). Ukraine is providing a sovereign guarantee.

Meanwhile technical assistance is being provided by the United States Agency for International Development (USAID) through its Energy Security Project for Ukraine. USAID has contracted Tetra Tech to implement the tender and other key aspects of the Energy Security Project.

‘Colossal’ damage, solar sector grinds to halt

The need for the battery storage arises from Ukraine’s growing share of renewable energy. In common with power grids everywhere in the world, the addition of renewables creates a need for balancing fluctuations in power input.

More uniquely to Ukraine of course, the country is facing immense difficulties since the invasion by Russia began nearly 300 days ago, acutely highlighting the need for energy security and stability.

Just yesterday, the IPS grid operator Ukrenergo’s CEO said damage to Ukraine’s power generation fleet from Russian missiles has been “colossal”.

Volodymyr Kudrytskyi said almost no thermal or hydroelectric generation plants in the country have been unaffected, as widely reported by outlets including The Guardian newspaper.

Fuel reserves stocked up prior to the invasion remain sufficient and work is ongoing to repair damaged infrastructure, while Ukrenergo hopes to be able to source spare parts from abroad to replace some equipment.

However, The Guardian quoted Kudrytskyi as having said it would be “inappropriate” to consider evacuating people from areas worst hit by the energy shortages.

Our colleagues over at PV Tech Premium in September meanwhile noted that the Ukrainian solar industry had ground to a halt, with more than 1GW, equivalent to 15% of capacity, lost since the start of the invasion. In 2019, the country was home to Europe’s third-largest solar PV market.

However, also reported by PV Tech Premium later the same month, industry groups including Ukraine’s national solar trade association ASEU have called for renewable energy to play a major part in the country’s recovery.

Pilot battery storage in Lithuania, another country joining ENTSO-E. Since this project’s deployment, a further 200MW has begun construction in Lithuania through BESS provider Fluence. Image: Litgrid.

‘We need energy storage on an industrial scale’

Another dimension to the BESS tender – and to the wider context – is that shortly before the invasion and war began, Ukraine, like several of its neighbouring countries, had reached an advanced stage of integration into the European Network of Transmission System Operators for Electricity (ENTSO-E).

In fact, a trial of the synchronised operation of the Ukraine and ENTSO-E’s transmission operators in 35 European countries started literally days before the war began.

Closer synchronisation gives Ukraine and other newly synchronised grids like Lithuania’s greater independence from Russia’s energy system and will support their transition to low-carbon energy sources like renewables paired with battery storage.

But, as the tender document points out, it also drives a need for flexibility and frequency response within the Ukrainian energy system.

In May 2021, that resulted in the country getting its first-ever megawatt-scale BESS, brought online by Ukrainian energy sector investment and infrastructure group DTEK, using a 1MW/2.25MWh BESS supplied by US technology company Honeywell.

That pilot and demonstration project was described at the time as an investment “into the future of Ukraine’s energy sector” that would “launch a new market for energy storage systems,” according to DTEK owner Rinat Akhmetov.

Earlier this month, at COP27 climate talks, DTEK’s CEO Maxim Timchenko said that the company, Ukraine’s largest investor in renewable energy, would not abandon its aim of reaching carbon neutrality by 2040.

“Russia’s full-scale war against Ukraine is demonstrating the importance of energy independence for security and peace across Europe, and renewable energy will have an increasingly important role to play. We also need to accelerate Ukrainian plans for decarbonisation,” Timchenko said.

Prior to the war, 70% of Ukraine’s energy came from nuclear, 10% from renewables and the remainder from other sources. Timchenko said the country could become a “European centre of green energy” with its “great potential for solar and wind energy”.

“We must install renewable energy sources in many parts of the country. And for flexibility, we need energy storage systems – batteries – on an industrial scale,” Timchenko added.

DTEK is currently looking to expand its pilot BESS plant to 20MW and has a further long-term renewable energy goal of delivering 30GW by 2030.

That would sit well with the national solar association ASEU, which has modelled that about 20GW of new solar could support a 50% renewable energy by 2030 goal.

Energy-Storage.news’ publisher Solar Media will host the 8th annual Energy Storage Summit EU in London, 22-23 February 2023. This year it is moving to a larger venue, bringing together Europe’s leading investors, policymakers, developers, utilities, energy buyers and service providers all in one place. Visit the official site for more info.

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Groundbreaking at the factory site was attended by federal and state politicians. Image: Fenecon.

Energy storage hardware and software company Fenecon has begun construction of a new factory in Germany which will repurpose electric vehicle (EV) batteries into stationary storage systems.

The new site in the Bavarian municipality of Iggensbach will produce large-scale battery energy storage systems (BESS) using EV batteries paired with energy management systems (EMS).

Called CarBatteryReFactory, the site’s construction in an industrial park officially began last week on 18 November with a ceremonial groundbreaking event.

Fenecon, which announced the development yesterday, said the project represents around €22 million (US$22.72 million) investment, with funding contributions of €4.5 million from the European Union (EU) Innovation Fund and €1.7 million from the local Bavarian Economic Development Corporation.

Some funds were also raised by crowdfunded investment, and Fenecon noted a community information and engagement event was attended by more than 200 local people in the evening following the groundbreaking.

Known as “second life” usage, batteries previously used for transportation can be repurposed for on-grid or off-grid stationary energy storage applications.

It’s an area of growing interest in the global battery storage industry, with McKinsey forecasting that some 227GWh of used EV batteries will be available by the end of this decade.

Earlier this year, McKinsey Battery Insights solution manager Nicolo Campagnol told our quarterly journal PV Tech Power that second life won’t be a dominant technology in the energy storage space, but will be a big niche and will play an important role.

Campagnol suggested also that especially for smaller BESS integrators, second life batteries could present a handy supply chain option when availability is constrained, as it continues to be at the moment.

Fenecon, which has been in the second life business since 2017, will be able to move up from small series production at its current plant to large series production at the CarBatteryReFactory by the end of next year, the company claimed.

“The recognition from the European Union and the funding from the Bavarian Ministry of Economic Affairs make this innovative project of industrialised manufacturing for the transition from mobile batteries to stationary batteries possible in the first place,” Fenecon founder and CEO Franz-Josef Feilmeier said.

“We are proud to further advance the 100% energy transition with this extremely useful secondary use of e-car batteries and to create urgently needed electricity storage capacities in Germany.”

In an article published on this site yesterday, various companies involved with second life batteries for BESS commented on how useful the technology could be in establishing a more sustainable battery industry based around circular economy principles.

Once batteries are below 80% capacity after a few years of use in EVs, they are deemed no longer suitable for that application. However stationary energy storage applications can be much less demanding of batteries – depending on how they’re used – and those secondary EV batteries can often serve them adequately.

In yesterday’s article, it was noted that ‘third life’ batteries could also become a useful niche in the market: after use for transport, the batteries could be used for a time for grid-stabilising ancillary services. Once they’ve degraded a bit further and lost a little more capacity, they could find their third purpose as backup power resources.

Fenecon noted however that initially production at its Iggenbach plant will begin using conventional batteries designed for BESS and begin large series production from EV batteries, including new and used, from 2024.

The production capacity of the factory has not yet been disclosed but Fenecon claimed it will be Europe’s largest second life-based factory.

Fenecon sees one of its main differentiators and strengths as being its EMS technology, which it claims has been designed to be future proofed. As well as renewable energy and battery storage controls, it is also designed to be able to integrate numerous other energy resources like heating.

At this year’s Intersolar Europe / Electrical Energy Storage Europe trade show in Munich, Fenecon’s Franz-Josef Feilmeier said that for both hardware and software, it would be hugely advantageous to the industry to have an open source ecosystem.

Enabling compatibility across different energy storage systems, EV chargers, heat pumps and other technologies would lower costs and increase accessibility. Feilmeier cited the example of smart phones, which are based on shared operating system platforms open to different app developers.   

Second life battery storage will be in focus in a feature article in the forthcoming Q4 2022 edition of PV Tech Power, due out in December. See here for more details on how to subscribe.

Energy-Storage.news’ publisher Solar Media will host the 8th annual Energy Storage Summit EU in London, 22-23 February 2023. This year it is moving to a larger venue, bringing together Europe’s leading investors, policymakers, developers, utilities, energy buyers and service providers all in one place. Visit the official site for more info.

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Publicity picture issued by Hyundai North America at last year’s LA Auto Show. Image: Hyundai North America.

Automaker Hyundai has begun offering home electrification equipment to customers in the US, including EV charging solutions, battery energy storage and solar PV.

After showcasing the Hyundai Home product range as a ‘proof of concept’ at the Los Angeles Auto Show in 2021, ahead of this year’s edition which opened last week, the South Korean company announced availability of the range in 16 states across the country.

In partnership with home electrification company Electrum, Hyundai North America aims to offer a home electrification one-stop-shop, with customers able to buy solar, battery storage and mobility solutions together.

The pair’s new online marketplace will connect customers with local installers of the distributed energy resources (DERs) in their area.

Called the Hyundai Home Marketplace, customers will get a dedicated energy advisor to talk through available options and purchases, including helping them determine the right system for their household’s needs.

As standard, three different installation bids will be offered for every order from a network of Electrum-affiliated electricians. Customers can then choose their preference from the three proposals they get.

The marketplace is equipped with an automated bidding platform that can assess what sort of incentives might be available to them from utilities or their local government, for example if net metering programmes are in place for solar PV, virtual power plant (VPP) programmes for batteries and so on.

Hyundai’s sideways move into the solar and storage market follows a more vertically integrated recent play by another major automaker.

General Motors (GM) last month launched a dedicated energy storage division, making residential and commercial and industrial (C&I) energy storage systems and energy management solutions which it is offering alongside its existing EV charger range.

GM is working with its preferred installer, SunPower, to also develop a home energy system comprising integrated EV and battery storage solutions as well as solar PV. That includes developing an auto range with vehicle-to-home (V2H) capabilities. GM has in recent months collaborated with two of California’s main investor-owned utilities (IOUs), Pacific Gas & Electric and San Diego Gas & Electric, to explore the potential of vehicle-to-home and vehicle-to-grid (V2G) technologies.

Similarly, Ford’s new all-electric version of its most popular truck, the F150, comes ready with V2H capability, in that instance developed in partnership with another of the US’ leading residential solar (and storage) companies, Sunrun.

In a recent interview with this site, Sunrun policy and market development senior director Chris Rauscher discussed a broad range of topics, including the tie-up with Ford and the roles V2H and vehicle-to-grid (V2G) technology could play in the US energy transition.

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