A sonnen home energy storage system. Image: sonnen.

German home energy storage and virtual power plant (VPP) company sonnen has deployed 86 of its ecoLinx batteries in a new-build complex in Florida, US.

Sonnen has partnered with sustainable homebuilder Pearl Homes to deploy its systems across the Hunters Point Energy Community in Cortez, Manatee County.

All 86 homes will have a solar PV plus sonnen ecoLinx energy storage system, meaning the ability to power themselves with clean energy in the event of a grid outage. Pearl Homes said the project is aimed at offering electrical independence from electricity bills to residents of the community.

The press release did not say which ecoLinx model would be deployed. They range from 12kWh to the largest at 30kWh, meaning the 86 combined total somewhere between 1GWh and 2.6GWh of energy storage.

The Hunters Point homes qualify as Net Zero LEED Plus, a mark of their sustainability credentials from the Leadership in Energy and Environmental Design (LEED) global building certification programme.

“We believe the Hunters Point community will serve as a ‘greenprint’ for the future of not only clean energy homes but entire sustainable, cost-effective master-planned communities. We seek out trailblazing partners, like Sonnen, for our projects because our focus has always been on building products and solutions that have the potential to change the world,” said Marshall Gobuty, founder, Pearl Homes.

Sonnen, which was acquired by Shell in 2019, is the largest home energy storage system provider in Germany and has recently been making inroads in the US market through partnerships with utilities and homebuilders.

The company specialises in deploying and then aggregating those systems in VPPs which can then act as one, larger energy storage unit to help relieve strain on the grid. In the US, it has done this in Utah, Wyoming and Idaho in partnership with utility Rocky Mountain Power and in New York with community choice aggregator (CCA) Sustainable Westchester.

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Iberdrola’s 50MW/25MWh Gorman project in County Meath, Ireland. Image: Iberdrola.

Spanish utility Iberdrola has commissioned a battery energy storage system (BESS) in Ireland that will contribute to grid security as more renewables come online.

Located in County Meath, in the east of the country, the 50MW/25MWh system consists of more than 4,000 modules in 16 containers and required an investment of €28 million (US$28.51 million). 

Dubbed Gorman, the battery will serve state-owned electricity transmission operator EirGrid for six years.

The commissioning marks the culmination of an initiative developed by EirGrid and peer SONI to reinforce the grid, according to Iberdrola, which said it plans to expand the BESS to 100MW in the future.

Iberdrola said battery storage projects are set to become an essential element in the electricity system because they improve the quality of electricity supply, ensure grid stability and reliability by balancing supply and demand, and guarantee the availability of additional green power when needed.

The company is planning to invest up to €100 million in new onshore renewable and storage projects in Ireland by 2025, by which time it aims to have 16GW of solar installed globally.

The project commissioning comes after German energy company RWE powered up a 60MW BESS last month in Ireland’s County Monaghan.

Mitsubishi Power revealed plans last week to enter the European energy storage market with four BESS projects totalling 371MWh for ION Renewables in Ireland.

This story first appeared on Solar Power Portal.

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Polar Night Energy’s sand-based thermal storage system. Image: Polar Night Energy.

The first commercial sand-based thermal energy storage system in the world has started operating in Finland, developed by Polar Night Energy.

Polar Night Energy’s system, based on its patented technology, has gone online on the site of a power plant operated by utility Vatajankoski.

The 4×7 metre steel container contains hundreds of tonnes of sand which can be heated to a temperature of 500-600 degrees Celsius. The sand is heated with renewable electricity and stored for use in the local district heating system.

It has a particularly strong use case in Finland which sees long and very cold winters, and was recently cut off from Russian gas supplies over a payments dispute. The storage system’s developers say it is cheap and easy to build.

The system can discharge a maximum of 100kW of heat power and has a total energy capacity of 8MWh, equating to up to 80 hours’ storage duration, but now authorities want to scale the system to one a thousand times bigger, or 8GWh, according to a report from UK broadcaster BBC.

“This innovation is a part of the smart and green energy transition. Heat storages can significantly help to increase intermittent renewables in the electrical grid. At the same time we can prime the waste heat to usable level to heat a city. This is a logical step towards combustion-free heat production,” said Markku Ylönen, co-founder of Polar Night Energy.

Vatajankoski also uses the heat provided by the storage to prime the waste heat recovered from their data servers so that it can also be fed into the district heating network.

It is the second major thermal storage facility based on a unique (if not novel) technological solution that has progressed this week. Swedish public utility Vattenfall is about to start filling a 200MW-rated thermal energy storage facility, effectively a giant water tank, in Berlin.

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Some system integrators, like Powin which delivered this BESS project in California, exclusively use LFP batteries. Image: Powin Energy.

Whilst growing in popularity for stationary energy storage, one project developer tells Energy-Storage.news that LFP batteries deliver lower returns than NMC ones, a claim we then put to battery intelligence firm ACCURE.

There has long been a debate going on in the energy storage industry about whether to use lithium iron phosphate (LFP) or nickel-manganese-cobalt (NMC) based batteries.

NMC has been the more popular choice historically and still today, driven by its popularity as cell chemistry of choice in the electric vehicle (EV) sector, which meant it scaled up quickly.

But LFP is quickly gaining momentum in energy storage thanks to its better safety record and, at least before the current supply chain spike in lithium carbonate prices, more competitive cost. Lithium and phosphorous are more abundant than nickel, manganese and cobalt and some studies also show that LFP batteries also have a longer cycle life.

One thing that is discussed comparatively less is the implication of LFP’s flatter voltage curve on an LFP-based system’s ability to provide ancillary services compared to an NMC-based one. But, more importantly, the higher cost of a common countermeasure to this can reduce returns for a large system, according to a German BESS project developer who spoke on condition of anonymity.

Flatter voltage curve for LFP

A flatter voltage curve means that when you discharge a battery there is a wide range of state-of-charge (SOC) in which the voltage changes only slightly. An NMC battery’s voltage is much more correlated with its SOC, making it easier to track SOC using voltage. You need to track SOC to prevent charge error or diverging charge between systems.

The developer says this means that LFP systems miss potential slots, and therefore revenues, specifically in the European FCR/aFRR markets due to daily outages for recalibrating the system.

He says that software fixes like column counting – metering of energy throughput and calculating the charge instead of measuring it – might work for simple storage configurations and small-scale applications.

“But if you operate more complex optimisation on large scale projects, software based alternatives to direct charge measurement have problems with increasing charge error and diverging charge between the systems, because column counting is just a ‘best guess’ estimate in the end,” he says.

Matthias Kuipers, senior expert at battery diagnostics intelligence software solution provider ACCURE, agrees this is an issue for LFP-based systems and the need to recalibrate has the potential to cause missed profits. But good software can largely get around this, he says, echoing what an academic also told Energy-Storage.news.

“I believe a smart battery design can help here. A properly designed BMS (battery management system) with some smart diagnostic algorithms together with an accurate and well calibrated current sensor should enable you to extend the time between recalibrations beyond a weekly or bi-weekly recalibration,” Kuipers says.

Parallel rack impedance issue

Our German BESS developer says that the issue with voltage/SOC means that LFP strings do not like to be connected in parallel behind a common inverter, as this results in unequal current distribution and faster ageing of some racks. This can affect bankability, with equal ageing of racks the ‘holy grail’ for financing projects.

Some big providers like Tesla solve this by adding a low power string inverter to each individual rack but it costs more and is less efficient than parallel rack configuration behind a central high power inverter, he adds.

Kuipers doesn’t necessarily agree: “Since there are a number of different architectures, I would be hesitant to claim one or the other. Especially, if there is a smart energy management system (EMS) operating the multi-rack system, it is possible to increase efficiency quite a bit, as you can operate the converters in more efficient states.”

The best solution, he says, is to “…use such a smart energy management system to continue operating the storage system whilst running a recalibration on one of the racks. And then we just go round and round the individual racks. This is possible because the racks can be operated individually. Sure, it is everything but a trivial task, yet if done correctly it can further reduce the missing profits.”

Our developer source concedes that newer LFP platforms designed by companies like CATL, might get around these issues.

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Anup Agarwal

Onward Energy has entered into a binding agreement to purchase 100% of the cash equity interests in a 1,171 MW operating solar portfolio from Global Atlantic Financial Group. The portfolio includes 11 projects in eight states. It will be the largest renewable investment in Onward Energy’s history, further expanding the company’s portfolio to over 6 GW of diverse power generation assets. 

“We believe that this acquisition of high-quality solar assets is a strong fit with our existing portfolio, consistent with our view of the energy transition and complementary to our growth strategy,” says Steve Doyon, Onward Energy’s CEO. “Working with Global Atlantic and their exemplary team, we were able to sign the agreement quickly and seamlessly.”

“This portfolio is part of a diverse set of solar investments that we’re proud to have built over the past seven years, and we believe that Onward Energy will be an excellent steward of these assets,” comments Anup Agarwal, chief investment officer of Global Atlantic. “We were pleased to reach an agreement and are committed to building our presence in this space as global demand for clean power continues to rise.”

Onpeak Capital LLC served as financial advisor and Mayer Brown LLP served as legal advisor to Global Atlantic. Milbank LLP served as legal adviser to Onward. The transaction is expected to close in the third quarter of 2022, subject to customary closing conditions.

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Aer Soléir head of investment Marcus Horgan (left) and Altea Green Power CEO Giovanni Di Pascale. Image: Aer Soléir

Irish developer Aer Soléir has signed an investment and co-development deal for 510MW of battery storage projects in Italy with Turin-headquartered Altea Green Power.

The pair signed a Share Purchase Agreement along with co-development agreements relating to four large-scale battery energy storage system (BESS) projects last week.

Aer Soléir said the development work is already completed on each of them and the Dublin-based company has bought the sites from Altea Green Power ahead of construction.

Three are in Puglia province, in the ‘heel’ of Italy’s boot-shaped geographical outline and the fourth is in Piedmont, in the country’s northwest region.

The two companies noted that the development of large-scale battery storage is in line with national energy minister Roberto Cingolani’s recent confirmation that Italy is setting a minimum renewable energy target of 70% by 2030.

Italy is also receiving a share of European Union post-pandemic economic recovery funding, of which a considerable portion is earmarked for green energy industry activities.

According to recently published data from analysis group Delta-EE, Italy is one of the four key markets leading Europe for energy storage deployment at present. The other three are Great Britain, Germany and Aer Soléir’s home market of Ireland.

As reported by Energy-Storage.news in May, Italy has arrived at more than 1.2GWh of battery storage capacity nationwide, although a huge amount of that – around 977MWh – is in the distributed energy storage segment rather than large-scale, according to the national ANIE Rinnovabili renewable energy association.

Market opportunities include frequency response on the pan-European market, but Italy’s grid operator, TERNA has also opened up the capacity market to batteries, awarding 1.1GW of contracts to new-build BESS in February through an auction.

In a recent interview, the CEO of UK energy storage developer-investor Gore Street Capital highlighted Italy as an “interesting market” with potential alongside Greece and Germany, as the company sought to expand internationally from its UK and Ireland development base.

“Italy is an interesting market we’ve looked at for many years but haven’t yet done anything in. It has a high level of penetration of solar and wind and it’s not as connected to the other mainland Europe grids because of the Alps, which creates an opportunity,” Gore Street Capital’s Alex O’Cinneide said.  

Aer Soléir CEO and founding partner Andy Kinsella meanwhile said last week that Italy is a “very attractive market,” in which the company already has large-scale wind and solar PV projects.

In April, Aer Soléir received a US$250 million funding commitment from US-based clean energy investor 547 Energy International, part of the Quantum Energy Partners equity investment group. The developer has about 20 employees and is seeking development-stage clean energy projects across the European Union.

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A solar and battery project Gannawarra, Victoria, completed in 2018 with some support from ARENA. The agency has supported seven large-scale BESS projects to date, four of those with advanced inverters. Image: ARENA.

Nearly A$4 billion (US$2.72 billion) of battery projects in Australia are in the running to receive financial support from the Australian Renewable Energy Agency (ARENA).

ARENA opened up its Large Scale Battery Storage Round at the beginning of this year, offering A$100 million in support for projects of 70MW or larger, which would use advanced, aka grid-forming, inverter technologies.

The agency said today that it has now shortlisted 12 projects totalling 3,050MW/7,000MWh out of a pool of 54 from which it received Expressions of Interest (EOI). The successful dozen, which have a total value of A$3.7 billion, and requested a total A$297 million of grant funding, are now invited to submit full applications.

They now have until 20 July to do so and a decision is expected to be announced before the end of this year.

As reported by Energy-Storage.news in January shortly after the round launched, maximum grant value is capped at A$35 million per project and ARENA said at the time it expected to support at least three projects.

It won’t be the first time ARENA has supported battery storage projects, nor the first time it has supported battery projects with grid-forming capabilities.

The first example of the latter was the Energy Storage for Commercial Renewable Integration (ESCRI) project in South Australia, which uses advanced inverters at a 30MW/8MWh battery energy storage system (BESS) supplied by Hitachi ABB Power Grids (now Hitachi Energy).

ESCRI was commissioned in 2018. It provides synchronous inertia and therefore grid stability to a remote region at the far end of transmission lines which has seen its local share of renewable energy – mainly rooftop solar and large-scale wind – grow rapidly.

Synchronous inertia is a vital application that has traditionally been done by thermal power plants that provide large rotating mass to the system.

Earlier this year, Energy-Storage.news reported too that a 50MW/50MWh BESS in the Broken Hill region of New South Wales will demonstrate the same capability. BESS system integrator Fluence signed an agreement with utility AGL to supply systems to that project, with ARENA providing A$14.84 million of it’s A$41 million total expected cost.

Two existing large-scale battery systems in Australia, Hornsdale Power Reserve in South Australia and Wallgrove in New South Wales, are being retrofitted with grid-forming inverter technology which should be in place by the end of this year, ARENA said.

“Advanced inverters that can help stabilise the grid are the missing piece of the puzzle that will support the transition to 100 per cent renewable energy penetration for short periods,” ARENA’s acting CEO Chris Faris said.

More generally, ARENA referred to the recently published Integrated System Plan (ISP) from the Australian Energy Market Operator (AEMO) which highlighted the critical need for large amounts of energy storage in the National Electricity Market (NEM) to maintain system stability as coal retires and renewables take over the lion’s share of generation.

Projects competing the new funding round must either be connected to the NEM or Western Australia’s Wholesale Electricity Market.

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The 1 MW photovoltaic array at NREL’s Flatirons Campus. (Photo: Werner Slocum, NREL)

In their new paper in Joule, “Embodied Energy and Carbon from the Manufacture of Cadmium Telluride and Silicon Photovoltaics,” National Renewable Energy Laboratory (NREL) researchers Hope Wikoff, Samantha Reese and Matthew Reese focus on the two dominant deployed photovoltaic (PV) technologies: silicon (Si) and cadmium telluride (CdTe) PV. These green technologies help reduce carbon emissions and meet global decarbonization goals – but their manufacturing processes can themselves result in greenhouse gas emissions.

“Green technologies are awesome, but as we are working to scale them up to an incredible magnitude, it makes sense to take a close look to see what can be done to minimize the impact,” says Samantha Reese, a senior engineer and analyst in NREL’s Strategic Energy Analysis Center.

To understand the overall impact of these green technologies on global decarbonization goals, the team looked beyond traditional metrics like cost, performance and reliability. They evaluated “embodied” energy and carbon – the sunk energy and carbon emissions involved in manufacturing a PV module – as well as the energy payback time (the time it takes a PV system to generate the same amount of energy as was required to produce it).

“Most advances have been driven by cost and efficiency because those metrics are easy to evaluate,” states Matthew Reese, a physics researcher at NREL. “But if part of our goal is to decarbonize, then it makes sense to look at the bigger picture. There is certainly a benefit to trying to push efficiencies, but other factors are also influential when it comes to decarbonization efforts.”

“One of the unique things that was done in this paper is that the manufacturing and science perspectives were brought together,” Samantha Reese continues. “We combined life-cycle analysis with materials science to explain the emission results for each technology and to examine effects of future advances. We want to use these results to identify areas where additional research is needed.”

The manufacturing location and the technology type both have a major impact on embodied carbon and represent two key knobs that can be turned to influence decarbonization. By looking at present-day grid mixes in countries that manufacture solar, the authors found that manufacturing with a cleaner energy mix – compared to using a coal-rich mix – can reduce emissions by a factor of two. Furthermore, although Si PV presently dominates the market, thin-film PV technologies like CdTe and perovskites provide another path to reducing carbon intensity by an additional factor of two.

This insight matters because of the limited carbon budget available to support the expected scale of PV manufacturing in the coming decades.

“If we want to hit the decarbonization goals set by the Intergovernmental Panel on Climate Change, as much as a sixth of the remaining carbon budget could be used to manufacture PV modules,” Matthew Reese adds. “That’s the scale of the problem – it’s a massive amount of manufacturing that has to be done in order to replace the energy sources being used today.”

The authors’ hope is that by illustrating the magnitude of the problem, their paper will cause people to take another look at the potential use of thin-film PV technologies, such as CdTe, and manufacturing with clean grid mixes.

Ultimately, accelerating the incorporation of low-carbon energy sources into the electrical grid mix is paramount.

“One of the big strengths of PV is that it has this positive feedback loop,” mentions Nancy Haegel, center director of NREL’s Materials Science Center. “As we clean up the grid – in part by adding more PV to the grid – PV manufacturing will become cleaner, in turn making PV an even better product.”

Read the full paper here.

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An aerial view of the Energy Superhub Oxford BESS. Image: Pivot Power.

Energy Superhub Oxford, a project with a lithium-ion-vanadium hybrid battery energy storage system (BESS) totalling 55MW, has officially launched.

The opening of its EV charging park today (July 5) marks the final step in delivering the project, which was covered in-depth in Vol.30 of PV Tech Power, Solar Media’s quarterly technical journal focused on the downstream solar industry. (You can read an extract of that special report here.)

The core component of the project is a combined BESS made up of a 50 MW/50MWh Lithium-ion system, supplied by Wärtsilä, and a 2MW/5MWh vanadium flow battery from Invinity Energy Systems. Optimiser Habitat Energy is taking the assets into market with its AI-enabled trading platform.

The plan has always been for the two to eventually operate as a hybrid asset, but a statement from Pivot Power provided to Energy-Storage.news indicates this is not yet the case.

“The vanadium flow battery was energised in December and has been charging and discharging since. With the site now officially launched, there will be a period of baselining alongside our partner Habitat Energy who will be optimising the dispatch of both assets,” a spokesperson said.

The project will provide its developer Pivot Power and the technology providers with invaluable learnings about how a combined asset can uniquely capitalise on market opportunities and the ways in which a vanadium battery can extend or optimise the lifetime of a lithium-ion battery, which has a much shorter lifecycle.

UK government body Innovate UK provided a quarter of the £41 million (US$55.8 million) cost of the Superhub. Its director of the ‘Prospering from the Energy Revolution’ challenge programme, Rob Saunders, said:

“The Energy Superhub Oxford project demonstrates the massive potential of creating integrated local energy systems, tailored to local needs, that will help cities and regions cut carbon in ways that work for communities and consumers. Our funding aim has been to help trial projects that are scalable and replicable, and it is great to see the Superhub concept rolling out to other areas.”

Indeed, Pivot Power wants to expand the Superhub model to up to 40 other locations in the UK of 50MW each meaning a total planned pipeline of 2GW. Most recently, it firmed up construction start dates for two sites in the West Midlands, one in a London suburb and one in Cornwall, altogether totalling 200MW/400MWh of energy storage (covered by our sister site Current).

It is continuing to use Wärtsilä’s lithium-ion-based BESS units to deliver these projects. In an interview for the PV Tech Power report, Pivot Power CTO Mikey Clark told Energy-Storage.news that it would wait to see how the vanadium battery performed in Oxford before considering using it for further projects.

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A battery storage site in Indiana. Image: NextEra Energy Resources.

Two gas peaker plants and a gas pipeline extension have been approved by regulators in the US state of Indiana, despite concerns over their costs relative to renewable energy and energy storage.

Consumer utility company Centerpoint Energy Indiana South received the green light from the Indiana Utility Regulatory Commission for its plan which included the construction of two gas combustion turbines totalling 460MW.

The proposal was included in Centerpoint’s Integrated Resource Plan 2019-2020, the forward-planning documents which it and other utilities in regulated markets in the US have to submit every three years.

It came after the IURC had denied it a separate 2018 request to build 850MW of gas plants, citing a reluctance to meet so much of the utility’s summer peak load with just one facility – around 77% of 2019 summer peak load and about 71% of modelled summer peak load for 2031 – but the newer proposal seemingly met the regulator’s criteria for cost and environmental impact.

However, the plan has met consistent opposition from the Indiana Citizens Action Coalition and from national environmental group the Sierra Club, both of which raised concerns during the approvals process.

When the 460MW turbine plants were proposed, their expected cost was submitted by Centerpoint as US$323 million, which would add around US$23 per month on average to its customers’ utility bills.

Yet as Citizens Action Coalition (CAC) pointed out, since then gas prices have risen sharply. Inflation has too, driving construction costs up.

Perhaps even more damning is that expert testimony given on behalf of CAC in November 2021 noted the utility’s cost assumptions for cheaper and more environmentally friendly renewable energy and energy storage alternatives were flawed and overstated.

‘Unneeded and expensive fossil gas plants’

“This outrageous decision approves unneeded and expensive fossil gas power plants that will significantly raise the cost of electricity for CenterPoint customers,” CAC executive director Kerwin Olson said.

Anna Sommer, a principal at energy consultancy Energy Futures Group, submitted expert testimony for CAC. Sommer said that if errors in Centerpoint’s IRP were corrected, a lower cost plan, including more renewables and storage and avoiding the need to build the gas plants, would have been selected.

The consultant also noted transparency concerns over the modelling used by the utility and Siemens PTI, which had been hired to conduct it – Siemens PTI offered to run the analysis again but wouldn’t offer the data it used so that Sommer could run modelling independently of that.

Sales forecasting offered by the utility to justify the need for the gas plants was also overstated, Sommer believed.

“Correcting certain inputs in the IRP modelling results in the selection of a plan that is much lower cost and does not include the combustion turbines,” Sommer said in November 2021 as she submitted testimony.

“The Company has not provided sufficient justification or analysis for its choice to build these gas plants, especially given the lack of support for its outdated load forecast and the flaws in its IRP modelling.”

Another expert, Michael Gorman of Brubaker and Associates, testified that Centerpoint did not justify the need for the capacity the two gas plants would provide until as far off as 2033. Gorman also noted that factors like the rise in gas price could impact the economics of the project.

Michael Goggin, representing the Sierra Club, said also that were the IRP to be conducted again with updated cost assumptions, larger quantities of wind, solar and energy storage would have been selected over gas generation. Goggin is a consultant with a company called Grid Futures.

Unsurprisingly, utility representatives refuted the testimonies of Goggin, Sommer, Gorman and others.

“The IURC’s approval of more expensive fossil gas plants in the middle of a utility affordability crisis and the climate crisis shows how out of touch our utilities and their regulators are with Hoosiers [people from Indiana] who are struggling to make ends meet and demanding a transition to clean, affordable energy solutions,” CAC’s Kerwin Olson said.

Olson added that CAC renewed its call for Indiana’s governor, Eric Holcomb, to immediately establish a taskforce to deal with the utility affordability situation, urging the state’s policymakers “to stand up for consumers instead of protecting monopoly utility profits”.

As our sister site PV Tech reported this week, net metering schemes for rooftop solar Indiana appear to be at an end. Meanwhile, Centerpoint Energy Indiana South did get 335MW of solar PV power purchase agreements (PPAs) approved in May, with the company targeting net zero for its Scope 1 emissions by 2035. Its next IRP is expected to be published in 2023 and the planning process is set to begin imminently.

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