Luigi Resta, president and CEO of rPlus Energies, pointing towards the Three Peaks Solar project, a project developed by Luigi and several rPlus principals, which was commissioned in 2016.

Renewable energy developer rPlus Energies has commenced construction of the 200 MW AC / 240 MW DC Appaloosa Solar 1 project located in Iron County, Utah.

Neighboring Appaloosa Solar 1 is the 80 MW AC / 110 MW DC Three Peaks Solar project. Completed in 2016, Three Peaks Solar was the second utility-scale solar project developed in Utah by the same leadership team that now heads rPlus Energies.

“We are proud to be back in Iron County with a third project, the largest to date,” says rPlus Energies’ president and CEO, Luigi Resta. “Iron County has been a fantastic, supportive community and we are happy to continue our approach to build in Utah, by Utah and for Utah with this project.”

Recently, Greenbacker Capital Management, a renewable energy asset manager, invested in Appaloosa Solar 1. The transaction represents the latest collaboration between a Greenbacker affiliate and rPlus Energies that recently developed, built and commissioned the 80 MW AC Graphite Solar project in Carbon County, Utah – Greenbacker Renewable Energy Company’s largest operational clean energy project to date.

“Building durable partnerships is critical to building the future of energy, and we at Greenbacker are incredibly pleased to continue our partnership with rPlus,” states Ben Tillar, VP of investments at Greenbacker. “We’re excited to contribute to utility-scale solar plants like Appaloosa, which will support green jobs and help Utah run on cost-effective renewable power.”

Sundt Construction, with experience in Utah including the rPlus-developed Graphite Solar Project in Carbon County completed in June 2022, is providing engineering, procurement and construction for Appaloosa Solar 1. The rPlus team will remain involved with construction management and community relations.

The Appaloosa Solar 1 project has two long-term power purchase agreements (PPA) in place with PacifiCorp on behalf of Meta. The contract was developed under Rocky Mountain Power’s Schedule 34 green energy tariff, which allows large customers to purchase renewable energy generated on their behalf.

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Michael Smith

The City of Bakersfield in California, in partnership with ForeFront Power, a developer and asset manager of commercial and industrial-scale solar energy and storage projects, has finished Phase 1 of a planned citywide solar electricity generating project.

Now completed, Phase 1 of the project is a 2 MW DC solar energy portfolio located at five sites. With an annual electrical output of 3.4 million kWh, Phase 1 alone is expected to save the city and taxpayers nearly $9 million in electricity costs over a 20-year period.

Under the terms of a power purchase agreement (PPA) with the City of Bakersfield, ForeFront Power developed, owns and maintains the city’s solar energy portfolio. ForeFront Power charges the city a fixed, below-market rate for electricity, which is locked in for the 20-year duration of the agreement. ForeFront Power will continue to operate and maintain the system at no cost to the city.

“City staff is always looking for innovative and forward-thinking opportunities that will keep Bakersfield ahead of the curve,” City Manager Christian Clegg says. “By investing in this project, we have made Bakersfield more energy efficient, setting ourselves up for a future of fiscal responsibility.”

“We applaud the City of Bakersfield for the sustainability leadership demonstrated by installing 2 MW DC of solar energy to power city facilities,” comments ForeFront Power CEO Michael Smith. “ForeFront Power takes care of every aspect of solar energy solutions for our public sector partners like Bakersfield. We want to give local government agencies an alternative to expensive, unpredictable energy expenditures with guaranteed performance and low costs from solar.”

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Erthos Inc., an energy technology company focused on utility-scale solar and creator of Earth Mount Solar PV, has 14 MW of projects under contract and a memorandum of understanding (MOU) for a single 107 MW DC project. These commitments span agreements with five utility-scale solar developers and signal the next phase in the march to deploy Earth Mount Solar PV technology at utility scale.

Chaberton Energy, with its headquarters in Maryland, focuses on community solar and is benefiting from Earth Mount Solar PV’s ability to deliver the desired energy on a fraction of the land compared to other solutions. Erthos and Chaberton Energy have executed two owner’s architect agreements for projects in the mid-Atlantic. 

“Erthos technology allows us to build projects in specific locations that present challenges in terms of land availability and visibility. We’re excited to collaborate with the Erthos team, and we look forward to the opportunity to deploy this technology at more locations,” says Stefano Ratti, CEO of Chaberton Energy.

Encore Renewable Energy, a community-scale renewable energy and energy storage development company with headquarters in Vermont, has signed an MOU with Erthos for a project in its portfolio.

“As a forward-looking company, our team is always looking to improve the value of our projects with innovative technology,” says Chad Farrell, CEO of Encore Renewable Energy. “Erthos is answering that call for a project of ours, significantly improving project economics with its novel earth-mounted approach.” 

Path Company, an energy services company that was founded in 2017 and has operations across the southern U.S., has agreed to use Earth Mount Solar PV for a community college project in its home state of Mississippi.

“With Erthos, we are getting a solution adapted to our specific site and project, provided by some of the most experienced professionals in the business,” says Russ Phillips, co-founder of Path Company. “We know our project is in good hands.”

Projects under contract will bring the installed base of Earth Mount Solar PV to 17 MW DC. Additionally, Erthos has signed an MOU for a 107 MW DC project with a yet-to-be-disclosed U.S. developer.

“In this case, the project has very high interconnection costs,” states Jim Tyler, CEO of Erthos. “Erthos offers a clear advantage here because it has two to three times the energy density of a tracker or fixed-tilt system. This makes it ideal for projects with high fixed costs.”

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Mary Powell

Sunrun was exclusively selected by Puerto Rico’s electric utility provider to help rebuild and transform the island’s energy system through the development of a 17 MW virtual power plant (VPP), the first distributed large-scale storage program on the island.

The VPP will help lower energy costs for all consumers, reduce pollution island-wide and help harden Puerto Rico’s fragile grid with reliable, abundant solar energy by networking together more than 7,000 Sunrun solar-plus-battery systems installed on homes.

Sunrun will spend the next year enrolling customers into the program and begin networked dispatches in 2024. Batteries enrolled in the VPP will continue maintaining adequate backup reserves to power through potential grid outages at participants’ homes. All customers with batteries are also eligible to enroll and can opt out at any point during the 10-year program.

“Puerto Ricans are ready to make the move to reliable independent clean energy solutions that will increase their sense of safety and security in their own homes,” says Sunrun CEO Mary Powell. “We’re solving energy insecurity on the island by switching the model so that solar energy is generated on rooftops and stored in batteries to power each home, and then shared with neighbors, creating a clean shared energy economy. That way, residents not only have control over their energy at home, but can also share power with their community and be compensated for it.”

“A huge thanks to our channel partners in Puerto Rico, who have endured through so many climatic events yet continue to help Sunrun deliver energy independence and peace of mind to thousands of Puerto Rican households,” Powell continues. “I also want to thank those dedicated to advancing clean energy policy on the island to make these projects possible – Governor Pierluisi, the legislature, the Puerto Rico Energy Bureau and the Solar and Energy Storage Association of Puerto Rico, as well as the U.S. Department of Energy, which has provided technical assistance to the rebuilding effort. It is critical we continue efforts to ensure there is clean, reliable and affordable power for all in Puerto Rico.”

In 2019, two years after Hurricane Maria dismantled the island’s electric grid, the Puerto Rico Energy Public Policy Act was passed by the Legislature to set the parameters for a forward-looking energy system that maximizes distributed generation. The Puerto Rico Energy Bureau (PREB) determined that VPPs were key to achieving the legislation’s goals of building a resilient and robust energy system and meeting Puerto Rico’s renewable portfolio standards.

The governing board of the Puerto Rico Electric Power Authority approved the terms of the agreement on October 26, 2022, and the agreement is subject to regulatory sign-off by the Puerto Rico Energy Bureau and the Fiscal Oversight Management Board.

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Sunrun crews install rooftop solar panels in San Juan, Puerto Rico. Image: Sunrun.

Residential energy solutions provider Sunrun has been selected to develop a 17MW energy storage virtual power plant (VPP) in Puerto Rico.

The Nasdaq-listed firm has been selected by the Puerto Rico Electric Power Authority (PREPA) to organise the VPP programme using distributed energy storage resources. It is part of an effort to rebuild the US territory’s energy system after the devastation of Hurricane Maria in 2017.

Sunrun said it is the first distributed large-scale storage programme on the island. The VPP will lower energy bills, reduce emissions and shore up the country’s grid by aggregating more than 7,000 Sunrun residential solar-plus-battery-storage systems, the company said.

It will start enrolling customers for the next 12 months and begin networked dispatches in 2024. Participants will be compensated for strategically sharing energy with the country’s grid, while systems will retain enough backup power for homes in case of a grid outage.

In the long run, VPPs should also reduce overall costs for electricity consumers by lowering grid costs, but they do require participants to give up a significant degree of control over their residential solar and storage resources.

The project is the result of the Puerto Rico Energy Public Policy Act, which was signed two years after Hurricane Maria and set the parameters to maximise the used of distributed energy resources (DERs). The Puerto Rico Energy Bureau (PREB) determined that VPPs were key to achieving the Act’s goals of building a resilient energy system and meeting the island territory’s renewable generation aims.

Another extreme weather event just a month ago, Hurricane Fiona, provided a stark reminder of the need such a rollout when it knocked out the island’s grid leaving practically the entire island – over three million people – without power.

Sunrun says its solar-plus-battery systems provided more than 350,000 hours of backup power to thousands of homes during Fiona. The company offers its systems on the island with the option of a monthly fee and no upfront cost, and the VPP announcement contained several testimonials from existing customers on the island.

“My solar and battery system kept my lights on and my family safe during Hurricane Fiona,” said Hector Jimenez, a Sunrun customer in San Juan, the capital.

“Because of the solar battery system we installed on the roof of our station after Hurricane Maria, our communications systems were powered all night and day during Fiona, enabling us to respond to emergency calls,” said former San Juan Metro Fire Station Lt. Francisco Cruz.

The VPP programme is subject to a sign-off by the Puerto Rico Energy Board and the Fiscal Oversight Management Board.

The US unincorporated territory has also been seeking to increase its utility-scale energy storage through a recent request for proposals (RFP) for co-located projects. It is targeting a total of 1,500MW of storage through both utility-scale and DER units, and a 100% renewable energy mix by 2050.

Sunrun has been involved in other high-profile VPPs in mainland US states such as California, where residential and commercial and industrial C&I batteries helped keen the lights on during extreme summer weather, and a programme in the New England region.

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Daryl Pilon

Standard Solar Inc., SolarPark Energy and Catalyst Power Holdings LLC have completed a 7.1 MW community solar project in York, N.Y. Standard Solar funded the construction and will own and operate the project long-term. SolarPark Energy developed the project, and Catalyst Power, an integrated provider of cleaner energy solutions for the commercial and industrial sector, is managing subscriber acquisition and customer service for the project.

“Tommy would have been so excited to see this project come to fruition,” Anne Cassidy, managing partner of SolarPark Energy, says about the late Thomas Guzek, founder of the project developer SolarPark Energy. “This is his legacy. He would have been honored to be here today, but he’s here in spirit, I am absolutely sure.”

“Much hard work and dedication went into making this community solar array a reality, one that will help the state of New York and the nation reach their ambitious sustainability goals,” comments Daryl Pilon, director of business development at Standard Solar. “It was inspiring to gather the development partners, local officials and community members to celebrate its launch and to honor the life of Tom Guzek, a true advocate and visionary in the renewable energy space.”

“Community solar offers a fantastic cost saving way for small and mid-sized businesses to access the benefits of solar – and small and mid-sized businesses offer community solar projects a strong base of subscribers to ensure successful projects,” states Gabe Philips, CEO of Catalyst Power. “New York’s community solar program is among the fastest and easiest ways for businesses to save money while supporting the local community. We’re thrilled to be working with Standard Solar and Solar Park Energy to fully subscribe the York community solar farm.”

“The realization of this project is a reflection of the importance of public-private partnerships and the progress that can be made when industry, state and local governments come together to act on climate change,” says Shyam Mehta, assistant director of distributed energy resources and energy storage at NYSERDA. “NYSERDA is proud to support this community solar project that will deliver the benefits of clean energy and electricity bill savings to nearby homes and businesses. Tom’s legacy and tireless efforts to advance the cause of solar energy will forever be enshrined in this project and other community solar projects across New York State that he helped bring to fruition.”

The single-axis tracker system is projected to produce approximately 10,794,000 kWh annually.

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ICL Group is an Israel-based global specialty minerals company, and is building the first large-scale LFP cathode facility in the US. Image: ICL Group.

Taiwan-based Aleees will provide its lithium iron phosphate (LFP) cathode manufacturing process technology for ICL Group’s US$400 million facility in Missouri, US.

Israel-based ICL’s LFP cathode manufacturing facility in St. Louis, expected operational in 2024, will be the first large-scale facility of its kind in the country.

ICL was awarded US$197 million through Bipartisan Infrastructure Law funding for the project, subject to ongoing negotiations with the Department of Energy.

A total of US$2.8 billion has been granted by the federal department for building a domestic battery supply chain, as reported by Energy-Storage.news last month.

The 120,000 square foot facility will produce LFP material for the global lithium-ion battery market through two production lines capable of producing 15,000 tons of a year. Phase One in 2024 will see the first line open while full production from both lines totalling 30,000 tons is expected the following year.

Phil Brown, president of Phosphate Specialties and managing director of North America for ICL, said: “The US$197 million investment from the Department of Energy (DoE) is crucial to building a domestic manufacturer, which can compete globally while providing a much-needed safety net for American manufacturers in the EV, battery and energy-storage industries.”

Aleees and ICL signed a memorandum of understanding (MOU) in July in which the Taiwan-based group granted licensed technology to ICL and agreed to provide the company with technical information to accelerate its project’s development.

A DoE publication on the winners of the grant money said that the location of ICL’s facility is in an area in significant need of investment to offset the loss of jobs in the automotive sector in past decades.

In October, Norway-headquartered battery manufacturing startup FREYR Battery announced an LFP cathode partnership with Aleees. FREYR will get licensing to produce and LFP cathode material based on the Aleees technology, starting at FREYR’s initial Giga Arctic gigafactory complex in Mo i Rana, Norway.

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 ribbon-cutting event at the Arlington Microgrid, Washington state. Image: Snohomish PUD.

Microgrid projects in the US states of Washington and Maryland combining battery storage, solar and vehicle-grid integration have gone online.

Arlington Microgrid in Washington

Snohomish County PUD, a utility serving customers in Snohomish County and Camano Island, cut the ribbon on the Arlington Microgrid and Clean Energy Center last week (25 October), near Arlington Airport.

The project combines a 500kW solar PV array and a 1MW/1.4MWh lithium-ion battery energy storage system (BESS) and a pair of vehicle-to-grid (V2G) charging stations. The BESS is a PowerStore unit provided by Hitachi Energy, a wholly-owned subsidiary of the Japanese conglomerate Hitachi, formerly called Hitachi ABB Power Grids. Mitsubishi Electric provided the V2G charging infrastructure.

The project is focusing on combining the resources for disaster recovery, grid resiliency and electric vehicle integration. Specifically, it will go into islanding mode and provide power to the PUD’s Arlington Community Office during a grid outage (such as one caused by a wind storm or earthquake), a facility with a peak load of 150kW.

The PUD said that the project will demonstrate multiple uses of energy storage, provide a plan and design to study for future microgrid projects, and increase grid reliability in case of an emergency. The University of Washington will provide modelling, data analysis and reports on the project until 2033.

“The Arlington Microgrid provides a foundation for meeting both today’s emerging energy challenges and the future energy needs in Washington state and beyond,” said Antonio Verga, Hitachi Energy general manager of Grid Edge Solutions.

The utility purchased two Nissan Leaf EVs for the V2G part of the project. The Leaf is the only widely used consumer EV in the US market which is bidirectionally-capable.

The solar portion of the project is part of a community solar programme, and the PUD said that 500-plus of its customers reserved 100% of its available units in under a month, while 10% of the units were granted to two community service providers to benefit low-income households.

As shown in a design of the project below, it will connect to a Clean Energy Center which will host the microgrid controller and demonstrate the technology to help educate the public about new energy technologies. A solar PV tree is also on-site. The Center has a peak load of 50kW, highest on winter days due to heating requirements.

The PUD received US$3.5 million in funding from the Department of Commerce’s Clean Energy Fund to complete the project, which cost a total of US$12 million.

Image: Snohomish County PUD.

Pacific Northwest National Laboratory (PNNL) produced two reports assessing the lifetime cost-benefit of the V2G aspect of the microgrid. It looked at various factors which influence the economics of the technology, including battery cell degradation, replacement, roundtrip efficiencies, wholesale andretail energy prices.

A PUD report said the PNNL’s study results indicated a strong correlation between the number of battery charge/discharge cycles and the cost of V2G.

The project also includes a 350kW backup diesel generator for when the BESS and solar array can no longer provide the islanding capabilities alone.

John Haarlow, PUD CEO/general manager, said: “Battery energy storage will help make critical infrastructure impervious to outages and help us meet energy demand when customer usage is at its highest. Vehicle-to-grid charging will allow us to work with homeowners and business owners to leverage EVs as backup or grid-assisted power sources.”

Read the University of Washington’s Techno-Economic Analysis of the Arlington Microgrid from February 2022 here.

Brookville Smart Energy Bus Depot in Maryland

In similar news, an EV charging station with a solar PV array, on-site BESS and microgrid controller allowing islanding mode was announced as operational yesterday (31 October).

The Brookville Smart Energy Bus Depot in Brookville, Maryland, will eventually power 70 electric buses belonging to the Brookville transit bus fleet, with 4.14MW of charging capacity.

It features a 3MW/4.3MWh energy storage system (ESS) from Dynapower which will store power to charge the electric buses during a grid outage, thus enabling the migrogrid capability. It also will also allow the Depot to participate in local utility Potomac Electric Power Company’s (Pepco) demand response programme.

How soon it will be charging 70 electric buses is not clear. 70 buses equates to half of the town’s bus fleet and Maryland as a state has a goal of 50% emissions-free buses by 2030.

A 1.6MW PV array and 1.9MW of diesel generators comprise the remaining power sources for the 6.5MW project.

Germany-headquartered firm The Mobility House is providing its ChargePilot software to optimise scheduling and the charging of the buses. The system coordinates with the charging capacity to source onsite power at the correct times throughout the day while ensuring that EV charging responds to load balancing and peak shaving commands from the microgrid controller.

Press releases from The Mobility House and Dynapower did not, however, go as far as saying that the microgrid will use vehicle-to-grid technology. Electrified buses hold a lot of potential for V2G technology thanks to larger battery sizes, more predictable schedules and a more consolidated pool of customers than the consumer EV space.

Public transit is a bit further behind when it comes to V2G participation than school buses. This is because they are out on the road a lot more and there are fewer bidirectionally-capable electric transit bus models. But, battery sizes typically 1.5-2 times bigger than a school bus and larger fleet sizes mean they also have significant potential as grid assets in the long run.

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The world’s first commercial-scale advanced compressed air energy storage (A-CAES) plant is in Ontario. Image: Hydrostor.

In an exclusive Guest Blog, Justin Rangooni, executive director of Energy Storage Canada, explains why hitting the country’s 2050 net zero target will be impossible without at least 8GW of energy storage by 2035.

When we talk about decarbonising Canadian electricity, we tend to focus on how it’s generated. How can we cost effectively expand hydropower capacity? Where are solar panels and wind turbines best located? How can we fully capture the potential of new fuels such as hydrogen and ammonia?

All vital questions, to be sure.

But no matter how effectively we develop our green generation options, we’re likely to fall short of our net-zero carbon ambition unless we knit the whole system together – and incorporate the ability to even out the variations in supply and demand – through a large-scale build-out of diverse forms of energy storage.

For the first time the scope of that build-out has been quantified, in a report recently commissioned by Energy Storage Canada. The report provides an estimate of the installed capacity of energy storage required, province by province, to optimally supplement green electricity sources and carry Canada over the net zero finish line.

And it’s a significant amount – in the range of 8 to 12 gigawatts nationally by 2035. Even at the low-end, that’s equivalent to Manitoba’s entire installed generating capacity as of 2020.

And while energy storage is already on a healthy growth trajectory with recent announcements in Ontario and Nova Scotia, national installed capacity today is less than 1 gigawatt, meaning we have a big gap to close.

But we need to close it if we are going to successfully realise the dual imperatives of meeting more of our energy end-use needs with electricity, and of enlarging the proportion of that electricity that comes from renewables and other non-emitting resources.

Even basic regulatory definitions are still missing

Each province has its own unique electricity supply mix and will follow its own path to net zero.

But the versatility of energy storage technologies will play a critical role in meeting electricity needs in all provinces, through maximising the efficiency and ability of existing and new generation, transmission, and distribution infrastructure. And providing potentially significant cost savings for customers.

Hydroelectric storage reservoirs, for example, can be used to level out supply to urban centres and capacity-constrained areas, without incurring the cost of transmission systems upgrades.

Additionally, energy storage will be instrumental in addressing the intermittent nature of wind and solar generation. And when paired with nuclear generation, energy storage can allow for more consistent and cost-effective production, decoupled from the vagaries of hour-by-hour demand.

Energy storage resources are a versatile, robust, and evolving group of technologies that offer a range of stability enhancing services to electricity systems, extending beyond the essential benefit of flexible capacity.

For instance, long-term storage options, with the ability to smooth out demand shifts over multiple days, will become more important as we drive fossil-fuel generation down to even lower levels.

But to fully unlock the value that energy storage can provide, policy makers and government agencies need to coordinate a revamp of the entire regulatory and legislative framework to include and accommodate energy storage.

Essential as energy storage is to our net zero future, it simply was not a consideration in the relatively distant past when our electricity regulatory frameworks were created.

Currently, we lack even basic regulatory definitions of energy storage in some provinces, as well as clear expectations and processes relating to the crucial issues of project siting and inter-connections with electricity grids.

Provincial power system planning and procurement approaches must also evolve to ensure pricing and other investment incentives reflect both the unique reality of energy storage deployment, and the scope of the savings and other benefits that energy storage can provide.

The variety and versatility of energy storage resources make them a critical component of a net zero electricity grid – a component without which Canada will not reach its net zero goals.

Download the report by Power Advisory for Energy Storage Canada, ‘Energy Storage: A Key Net Zero Pathway in Canada’ here.

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Battery storage: perhaps not as big as pumped hydro, but certainly quicker and easier to build. Image: Fluence.

There is growing consensus from European Union policymakers and regulators that energy storage is vital to securing affordable and low carbon energy, but the technologies still face market challenges.

As a relatively new and complex technology with a wide variety of different use cases open to it, battery-based energy storage isn’t yet being made the most of, Lars Stephan, policy and market development manager for Fluence, told Energy-Storage.news.

In May, as the European Union (EU) launched REPowerEU, the energy storage industry’s initial disappointment at being excluded from an early leaked draft of the document – which set out pathways to reduce dependence on Russian gas and accelerate decarbonisation – gave way to a more positive feeling.

REPowerEU in its final form did include mention of energy storage and noted that the ability to balance the grid as well as supply and demand for power in the European grid is crucial to long-term goals.

That said, it was short on details of how this would be achieved, and more attention was paid to other areas like green hydrogen and carbon capture and storage, which are arguably less mature technologies.

While REPowerEU sets a target for 45% of Europe’s energy generation to come from renewable sources by 2030, and the strategic plan mentioned energy storage’s role in getting there, it did not set targets or benchmarks for the amount or proportion of storage relative to generation.   

Lars Stephan said he believed there is also growing consensus from EU policymakers in Brussels that energy storage needs to be part of upcoming electricity market design reform and will have an important role to play.

“However, it is yet to translate into tangible policy actions to enable and support energy storage. This is the major challenge that we’re seeing today,” Stephan said.

Although market analysts at BloombergNEF and others have forecast that REPowerEU will be a major driver for activity in the market, at present, Europe’s deployment of energy storage has been slower than in regions like the US, Australia and the UK, despite having had a head start on at least two of those territories.

Trade group the European Association for Storage of Energy (EASE) has modelled that the EU could need 187GW of energy storage by 2030, which given that it only managed about a gigawatt in 2021, seems a steep climb.

Industry unites behind urgent call to policymakers

In July, the CEOs of Fluence and eight other organisations from across the sector sent an open letter to European policymakers, urging for the introduction of “adequate targets and policy frameworks” to make it happen.

There are now 28 co-signatories to that open letter, and among other energy storage industry players like Gore Street Capital and Kyon Energy is Swedish state-owned utility company Vattenfall and various research institutions.

“The industry is uniting to underline that we need to build an energy system that is able to integrate much higher levels of renewable energy – otherwise we will fail to reach the targets set out by the European Union,” Lars Stephan said of the letter and the push behind it.  

“Europe thus needs a rapid rollout of proven and scalable technologies to increase grid flexibility and enable the safe and efficient integration of renewable generation.”

Stephan said that grid-scale energy storage is one of a number of important tools in decarbonising and securing energy supply, along with demand response, electrification of vehicles and buildings, distributed energy storage, and other technologies.

However, while all of these technologies have a role to play and a technology agnostic view should be taken, large-scale battery storage systems can be deployed in about a year-and-a-half and have an immediate impact in reducing the volatility of electricity pricing. Adapting network codes for demand response, for example, could take “years to have a tangible effect,” Stephan said.

“At the same time, especially during the energy crisis, we see huge wholesale price spreads with high electricity costs driven by gas-based power generation. In this situation every megawatt, every gigawatt of storage, helps reduce spreads and thus bring prices down.”

Pumped hydro energy storage (PHES) already does this today: reducing the overall cost of electricity by shifting cheaper electricity generated at off-peak times into the evening peaking hours. Essentially, this is what the EU’s short-term market intervention strategy aims to do, by asking EU Member States to reduce their peak consumption of grid electricity during high stress periods.

“Large capacity of [battery-based] energy storage integrated as a peaking asset would have the same effect on the system. While utility-scale storage may still take 12-16 months to be operational from the investment decision, it is faster, more flexible than any alternative.”

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