The coal plant at Uskmouth while still operational in 2013. Image: Chris Allen.

Investor Quinbrook Infrastructure Partners has acquired exclusive project development rights for a 230MW/460MWh battery energy storage system (BESS) in Wales, UK.

The BESS will be located at the site of the former Uskmouth coal fired power station in south Wales, which closed in 2015, and will utilise existing power transmission infrastructure including its 230MW grid connection. The development includes a modification of the grid connection agreement and a planning application to be determined by the local Newport City council.

The project development rights were acquired from Simec Atlantis Energy and the BESS is expected to come online towards the end of 2024. Quinbrook has partnered with storage optimiser Energy Optimisation Solutions (EOS) in the origination and development of the project.

Quinbrook and EOS are jointly undertaking the design and development phases of Project Uskmouth with Quinbrook affiliate Private Energy Partners leading equipment procurement, construction and operational management.

Habitat Energy, a battery storage optimiser which was acquired by Quinbrook late last year, will be engaged to optimise the Uskmouth assets when operational.

Quinbrook’s policy is to prioritise the use of local contractors and specialists during construction works and, where possible, the project will utilise the existing railway access for logistical requirements in order to minimise local impacts from construction activities.

Rory Quinlan, co-founder and managing partner of Quinbrook, said: “If the UK power system is to meet its 2030 renewables targets (of 95% decarbonised power generation), battery storage will need to increase significantly to address urgent stability and flexibility requirements.”

“Almost 10% of UK grid capacity is expected to be provided by battery storage by 2030, representing an estimated £20 billion (US$24.5 billion) of new capital investment. Project Uskmouth is a timely example of how specialist energy infrastructure investors like Quinbrook can identify new opportunities of substantial scale and positive impact arising from the energy transition.”

The project’s two-hour duration is indicative of a wider trend in the UK BESS market to move past one-hour systems, driven primarily by a shift to merchant, wholesale energy trading revenues and away from solely providing grid frequency response services.

Recent examples, covered by Energy-Storage.news’ sister site Solar Power Portal include TagEnergy and Harmony Energy’s Chapel Farm BESS and Amp Energy’s 400MW/800MWh Scottish Green Battery Complex.

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Installation of a commercial-scale battery system in Ontario, Canada. Image: Sungrid.

Energy storage can enhance the reliability and lower the costs of operating and maintaining Ontario’s electricity distribution network, but current rules and regulations make that tricky.

Batteries are being seen as a useful tool to help add flexibility to electricity networks and at transmission and distribution (T&D) grid level are often described as “non-wires alternatives” (“NWAs”) to expensive investment in new infrastructure.

However, according to a new report from the trade association Energy Storage Canada, local distribution companies (LDCs) in Ontario are finding “several legislative and regulatory barriers” to deploying energy storage as NWAs and from recovering the costs of investing in them.

In a Guest Blog for this site last week, Energy Storage Canada executive director Justin Rangooni wrote about how energy storage is a proven technology class that can provide peaking capacity, flexibility in operations and enhance the reliability of networks for LDCs, which operate as regulated utilities.

Rangooni noted in his blog that many of the costs associated with investment in energy storage can be offset if storage technology – so versatile that it is often compared to a multi-purpose ‘Swiss Army Knife of the grid’ – would be allowed to earn from multiple revenue streams.

In other words, while being used for the LDCs’ purposes as NWAs, the storage systems could also earn revenues from the wholesale market, for example.

This market participation would also be compatible with the regulator Ontario Electricity Board’s 2021 instructions that distribution companies should utilise technologies like energy storage, energy efficiency and demand response to address their system needs and “avoid or defer” the need to invest in T&D infrastructure.

The OEB has said it is open to allowing LDCs to find new ways of cost recovery and risk allocation and that the utilities should be allowed to participate in the wholesale market.

Meanwhile Ontario energy minister Todd Smith has explicitly said that policies supporting NWAs versus traditional forms of investment “will be essential in maintaining an effective regulatory environment amidst the increasing adoption of Distributed Energy Resources (DERs)”.

However, other codes and guidelines that OEB currently has in place, as well as government regulations, are preventing this from happening, as yet.

Energy Storage Canada commissioned consultancy Power Advisory to look into the issues associated with LDC deployment of energy storage as non-wires alternatives for its new report. Power Advisory also examined four different potential ownership models through which it could work.

Analysis found that even if traditional infrastructure investment had lower upfront costs, energy storage systems participating in market opportunities such as those overseen by the Ontario Independent Electricity System Operator (IESO) would have lower costs, which ultimately are rate-based and passed onto consumers (see below).

Revenue offsets reduce cost of distribution services, according to analysis in the white paper. Image: Energy Storage Canada.

The white paper report, ‘Leveraging energy storage for distribution services: Howmaximizing revenue streams can lower costs to electricity customers,’ examine ownership models as follows:

Utility owned and operated energy storageThird-party owned and operatedUtility owned and third-party operatedUtility and third-party shared ownership and operations

The authors considered energy storage to be able to provide a range of applications in addition to capacity for the utilities. These include behind-the-meter services such as demand management or peak shaving, as well as front-of-the-meter services to the regional or bulk grid, like transmission or wholesale market services, ancillary services and more.

Importantly, the white paper notes that while the analysis weighs up the pros and cons of each approach, it does not make specific recommendations in favour of either. The authors and Energy Storage Canada instead hope to prompt consideration and conversations around which may work best.

It also highlights the specific barriers, from Ontario’s electricity rate design regime to barriers to uncertainty over what sort of revenues could be earned from stacking multiple value streams.

The white paper can be downloaded from Energy Storage Canada’s website here.

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Connected Energy will soon launch a utility-scale product. Image: Connected Energy.

Matthew Lumsden, CEO of second life application battery energy storage solution (BESS) provider Connected Energy, talks Energy-Storage.news through scaling up the business in preparation for an EV boom from 2024/2025.

The UK-based firm raised £15 million (US$18.4 million) from five new investors to scale up its business last week, as reported by Energy-Storage.news. The company was founded in 2015 and develops and designs BESS units using second life batteries from electric vehicles (EVs), with Renault its main supplier to-date.

With the help of subcontracted assemblers, it collates the batteries into blocks or modules made up of one type of battery with the same shape, size and cooling needs, and aggregates blocks into whole BESS units. Its key building block is a 360kWh unit made up of 24 Renault Kangoo van batteries and has mostly been deployed in commercial & industrial (C&I) settings.

Its latest fundraise round included subsidiaries of Caterpillar and Volvo Group, which manufacture large EVs and will be able to provide Connected Energy with batteries.

As reported last week, here, Lumsden says the latest fundraise round is about scaling up the size of the company’s product to a utility-scale offering in order to be ready for 2025 onwards, when the number of EVs on the road – and associated second life battery availability – really takes off.

“We’ve raised enough cash to build a 40MWh system that will demonstrate the technology at scale, but then also prove some of the new business models which we think you need to scale up second life energy storage,” Lumsden says.

“So it’s really about getting a bankable business model in place, whereby come 2025 when the real volumes of batteries start to come into play, we’ve got a proven technology and a proven business model that infrastructure investors will back, so that we can really start to build out some larger scale systems.”

Connected Energy’s CEO Matthew Lumsden. Image: Connected Energy.

The new 20MW/40MWh utility-scale offering will be called M-STOR. Lumsden wouldn’t be specific but says it is looking at sites in the UK and Europe for its first deployment. “It’s not just a demonstration system, it’s a commercial system, so it’s about getting the best deal.”

A big part of the second life application business model for utility-scale, he says, centres around the relationship with suppliers to ensure a ‘flow of batteries’ and performance guarantees that will carry through a system’s 30-year lifetime, and a cost model that is competitive and attractive relative to ‘first life’, i.e. new battery-based systems. Another aspect is having a good BMS (battery management system) since batteries will not be uniform.

Lumsden: “Our secret sauce is all about having a BMS that communicates with 1,000 batteries, all of which have slightly different states of health and some of which might come from different manufacturers. It’s all about how you control them and aggregate them all as one system relative to their respective states of health, performance, characteristics, costs, etc.”

Connected Energy is also implementing AI into its algorithms to learn more about how batteries behave, both to optimise its systems technically and commercially but also track and isolate anomalies, he adds.

When asked what changes he’d like to see from the wider industry to make developing and deploying second life-based solutions easier for companies like his, Lumsden makes an interesting point around safety standards.

“The key next step is really to get some good standards around second life batteries, so that they’re being used by people who are using them safely and you’re managing the risks associated with second life batteries. We need to get to the point where there’s a bit of regulation and safety parameters around operating systems using second life, as there isn’t any specific regulation around it at the moment,” he says.

“I think it’s important that we get to a point where second life systems are being developed according to certain standards by people who understand how to do it, so that we mitigate the risk of any thermal event? A big, big focus from us has been absolute safety, so we will only use batteries if the OEM will collaborate with us and they have to be happy with the way we’re doing what we do.”

Today, Connected Energy has deployed systems in the UK, Belgium, Netherlands and Germany and wants to expand in Europe and eventually into the US too, which would require partnering with a local system integrator to carry out the assembly process there.

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Solar array at a Boundary Power R-Series SAPS installation. Image: Boundary Power.

The government of Western Australia has begun a drive to deploy at least 1,000 renewable energy off-grid power systems aimed at bringing resilient electricity supplies to communities and customers.

Called standalone power systems (SAPS), the technology combines equipment including battery storage and solar PV. The state government today announced its rollout will commence with 180 installations and a funding commitment of A$37 million (US$25.63 million) for the distributed resources.

While SAPS are growing in popularity in Australia, particularly in rural areas, the Western Australian push is thought to be the largest initiative of its type in the country to date.

Rather than stretching power lines over long distances, customers can use on-site generated power and are likely to experience far fewer outages – up to 90% fewer, in some cases – according to  Western Power, the state-owned energy company which will administer the programme.

They also reduce emissions associated with electricity production and use, enabling nearly all of the site’s demand to be met with solar PV. Systems will often have generators too, but purely as backup.

WA energy minister Bill Johnston said the government will seek to deploy its 1,000 systems over the next four years in a statement.

Johnston also said installation will create 90 jobs, including 15 apprentice positions, as well as supporting local businesses which will manufacture, install and commission the units.

Energy-Storage.news spoke today with one of the companies selected to provide the SAPS, Boundary Power. Boundary Power is a joint venture between another state-owned energy company, Horizon Power and electrical engineering company Ampcontrol, set up to focus on the SAPS market.

Boundary Power will provide 101 of the SAPS units, while green energy installer Hybrid Systems Australia will deliver the remaining 79.

Boundary Power’s modular R-Series brand SAPS solution will be used at the sites, a representative told Energy-Storage.news today. The sizing and capacity of batteries and generation equipment will vary at each site to some extent, based on customer requirements, the representative said.

At this stage, Boundary Power said it couldn’t yet provide specific information on the sizing and duration of battery systems.

However, for a general idea, the R-Series spec sheets show that the systems range from 10kVA systems using 7.92kW solar arrays with 6kW solar inverter, coupled with 16kW battery inverter and 16.8kWh battery capacity up to 31.68kW solar arrays with 24kW solar and battery inverters, and 67.2kWh battery energy storage on the 25kVA models, with sizes and capacities in between.

The systems are tested within Boundary Power’s workshop before being taken to the field

According to Western Power, the process of installing SAPS begins with assessments of the customers load and energy usage patterns, to which their new off-grid solution is then designed to match.

The initial rollout seeks to replace reliance on about 762km of overhead power lines, in the process freeing up land for agricultural use and crucially reducing the risk of bushfires caused by problems with power infrastructure going to remote areas.

Systems will be deployed in WA’s south-west, eastern and north-west regions.

Elsewhere in the state, the government said in announcing its annual budget earlier this month that it has committed to closing its two remaining state-owned coal power plants by 2030 and will invest A$3.8 billion into a transition plan, including the installation of large-scale battery storage. The budget also pledged money to the local battery manufacturing value chain.

SAPS can increase renewable energy usage, reduce costs, outages and bushfires

According to Boundary Power’s representative, the SAPS contracts it has signed with Western Power includes a number of key performance indicators (KPIs) that the companies are bound by their commercial terms not to disclose.

They did note however that the SAPS can provide “a renewable percentage over 90%”, which is in line with Western Power’s own claims on the clean energy aspect of standalone power systems.

While the government said only that the SAPS will begin to be switched on in early 2023, Boundary Power’s spokesperson offered a few more details into the project timelines.

“The team will be commencing site visits by the end of June 2022 with onsite deployment in early 2023. It is anticipated that all sites will be commissioned by the end of 2023,” the representative said but also pointed out that the timeframe is “indicative only and depends on several factors”.

“Each individual system is commissioned individually; thus “power on” will happen all throughout the year,” according to the representative.

“Western Power’s traditional network of poles, wires and substations spread is now transitioning to standalone power system technology as a modern generation mix that better meets the needs of customers,” energy minister Bill Johnston said.

In February, the Australian Energy Market Commission (AEMC) which has a regulatory role over the country’s National Electricity Market (NEM), ruled that standalone power systems can participate in the market. Staged introduction will begin in August although states can opt-in or out.

“This [decision] allows electricity distributors to establish SAPS in communities where stand-alone power may be cheaper, safer and more reliable than grid supply, in jurisdictions that have opted into the new framework,” AEMC chair Anna Collyer said at the time.

“Particularly in remote, bushfire-prone areas, SAPS do away with the need to replace damaged grid connections at significant expense. In fact, the power infrastructure that connects communities to the grid can also cause bushfires, which is another reason SAPS are attractive alternatives to traditional network connections in those areas.”

Collyer said standalone power systems – including microgrids and individual customer installations — are becoming more viable as costs decrease and technology improves. Maintaining and replacing older power lines and other infrastructure comes at huge cost to a country as big as Australia, according to the AEMC chair.

“This is a timely rule change as we continue to transition to a renewable energy future. It increases the reliability and resilience of energy supply in remote areas, as well as reducing network costs for all customers.”

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In a new comprehensive literature review, researchers at the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) have discovered that alternatives to recycling may have untapped potential to build an effective circular economy for solar photovoltaic (PV) and battery technologies. These alternative strategies, such as reducing the use of virgin materials in manufacturing, reusing for new applications and extending product life spans, may provide new paths to building sustainable product life cycles.

These insights come after an analysis of more than 3,000 scientific publications exploring the life cycle of the most common PV and lithium-ion battery technologies, including starting materials, environmental impacts and end-of-life options. The NREL researchers examined 10 possible pathways toward a circular economy. The findings highlight key insights, gaps and opportunities for research and implementation of a circular economy for PV and battery technologies, including strategies that are currently being underutilized.

Demand for PV panels and lithium-ion batteries is expected to increase as the United States shifts away from fossil fuels and deploys more clean energy. Creating a robust circular economy for these technologies could mitigate demand for starting materials and reduce waste and environmental impacts. Circular economy strategies also have the potential to create clean energy jobs and address environmental justice concerns.

“If you can keep them as a working product for longer, that’s better than deconstructing it all the way down to the elements that occurs during recycling,” says Garvin Heath, senior environmental scientist and energy analyst and distinguished member of research staff at NREL. The researchers note the emphasis on recycling may overlook the challenges and opportunities that research into other strategies could reveal. “And when a product does reach the end of its life, recycling is not the only option.”

The deconstruction process takes more energy and generates more associated greenhouse gas emissions to then build into another product than keeping the first product in use longer, Heath continues. He, along with his NREL colleague Dwarakanath Ravikumar, are lead authors of the 52nd annual Critical Review of the Air & Waste Management Association, titled A Critical Review of Circular Economy for Lithium-Ion Batteries and Photovoltaic Modules — Status, Challenges, and Opportunities, which appears in the June edition of the Journal of the Air & Waste Management Association. Their co-authors, also from NREL, are Brianna Hansen and Elaine Kupets.

“People often summarize the product life cycle as ‘take, make, waste’,” Heath adds. “Recycling has received a lot of attention because it addresses the waste part, but there are ways to support a circular economy in the take part and the make part, too.”

Recycling to recover the materials used in the technologies is preferable to discarding them in a landfill, Heath states. He believes the industry should focus on starting with an original product design that already utilizes fewer materials, especially less hazardous ones.

The authors also note that challenges remain in developing PV and battery recycling methods. There are currently no integrated recycling processes that can recover all the materials for either technology and existing research has focused more on lab-scale methods.

NREL is already leading efforts to improve PV reliability, extend PV life spans, reduce the use of hazardous materials and decrease demand for starting materials. This includes leading the Durable Module Materials Consortium (DuraMAT), which is researching ways to extend the useful life of PV modules, and the Bio-Optimized Technologies to keep Thermoplastics out of Landfills and the Environment (BOTTLE) Consortium, which is developing ways to improve the recycling of plastics.

NREL is also a partner in the Argonne National Laboratory-led consortium ReCell, which works with industry, academia and national laboratories to advance recycling technologies along the entire battery life cycle for current and future battery chemistries.

The U.S. Department of Energy’s Advanced Manufacturing Office and Solar Energy Technologies Office funded the research.

Image: Andreas Gücklhorn on Unsplash

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Another EDF Renewables project, Desert Harvest 1 Solar project in California

Ameren Corp. subsidiary Ameren Missouri is acquiring the company’s largest solar facility, a 200 MW solar installation in central Missouri that is expected to create more than 250 construction jobs.

The facility will be acquired pursuant to a build-transfer agreement with EDF Renewables North America. Known as the Huck Finn Solar Project, it will be constructed on the border of Missouri’s Audrain and Ralls Counties. With timely regulatory approvals, the project could begin generating clean energy as soon as 2024.

“Developing Huck Finn is good for all of our customers because it provides clean electricity, creates economic opportunity and injects millions of dollars into the community over the life of the project, which will have widespread additional benefits,” says Mark Birk, chairman and president of Ameren Missouri.

“EDF Renewables is pleased to partner again with Ameren to help them execute on the transition to cleaner forms of generation,” mentions Eric Spigelman, director of origination and power marketing at EDF Renewables. “Ameren shares in our mission to deliver affordable, clean, reliable energy while at the same time growing the economy.”

Huck Finn is designed to generate more than 25 times the amount of energy of Missouri’s largest existing solar facility. It is the latest project to be part of Ameren Missouri’s planned addition of 2,800 MW in new, clean renewable generation by 2030 and the ninth solar facility that the company has announced or put in service since 2019. Together, these nine facilities represent more than 360 MW of clean energy generation capacity.

“Our customers will benefit from technological improvements that make solar generation an adaptable resource where we can get more energy from previously unused locations, including parking lots and garage rooftops,” comments Ajay Arora, chief renewable development officer at Ameren Missouri. “In the coming months, we anticipate taking more steps to demonstrate Ameren Missouri’s commitment to clean energy generation.”

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IESA’s VISION 2030 report was launched at India Energy Storage Week earlier this month. Image: IESA.

To integrate a targeted 500GW of non-fossil fuel energy onto its networks by 2030, at least 160GWh of energy storage will be needed in India by that time, according to the India Energy Storage Alliance (IESA).

This energy storage capacity would include front-of-the-meter grid-scale storage, storage for integrating renewable energy directly, storage for distribution and transmission networks and for ancillary services provision to balance the grid, according to a new report from the Alliance.  

IESA was founded by energy consultancy Customized Energy Solutions 10 years ago to promote the advancement of energy storage, green hydrogen and e-mobility technologies in India and now has hundreds of member organisations.

The group has just published the VISION 2030 report, based on analysis of India’s energy sector. As the name implies, VISION 2030 outlines the requirement for energy storage in the country as well as recommended actions for both policymakers and private companies to achieve its goals.

Indian Ministry of Power joint secretary Ghanshyam Prasad contributed a foreword to the report, pointing out the vital role energy storage will play in ensuring safe and reliable grid operation as shares of renewable energy increase.

“It is imperative for India to assess its storage capacity requirement in the coming years and formulate a plan for its implementation, keeping in view the energy transition in the Indian grid,” Prasad wrote.

Non-fossil fuel generation in the country has already reached 156.83GW, or 40.1% of the total generation mix, while peak demand for energy as of July 2021 exceeded 200GW.

The authors noted the many efforts to promote energy storage that have already been made, which began in around 2013 but have gathered pace rapidly since 2018. The most recent developments include Ministry of Power procurement and utilisation guidelines, and a pilot tender for 500MW/1,000MWh of standalone storage from the Solar Energy Corporation of India (SECI).

From peaker plant replacements to frameworks for renewables-plus-storage tenders

International energy market dynamics, such as the volatility of pricing for gas and questions around availability of coal further highlight the importance of acting promptly however, the report said.

As grid reliability becomes an issue at renewable penetration exceeds 50% – the threshold India is set to reach by 2030 – the country has what VISION 2030 described as a “unique opportunity” to establish itself as both a major market for energy storage deployment and as a manufacturing centre for related technologies.

From recent government measures to support 50GWh of new advanced chemistry cell (ACC) battery annual production capacity in the country, roughly 10,000 employment opportunities would be created for every gigawatt-hour of that production capacity, IESA estimated.

From analysis of the energy sector the IESA team arrived at the 160GWh figure and offered its recommendations on how to get there:

Peaker plants, which run on fossil fuels and are only called into action at times of peak demand, should be replaced by 2030-2035 with clean energy assets, which might include combinations of renewable energy with storage.A comprehensive energy storage policy that includes phased targets for deployment and long-term planning strategies should be introduced.Energy storage targets should not be limited to renewable energy integration applications alone and should be applied across the entire value chain from ancillary services and peak power to deferral of investment in transmission and distribution (T&D) upgrades.A unified procurement framework for energy storage should be created.A fund should be set up to support the deployment of large-scale storage in the near term, from which learnings can be made to enable successful future developments.Planning for India’s optimal generation mix should incorporate energy storage.Studies should be carried out to determine India’s energy storage targets.A three to five-year “pipeline” for tendering of renewables-plus-storage resources should be created to offer confidence to the industry to invest in manufacturing and capacity building.

According to IESA, only about 28MW/20MWh of front-of-the-meter (FTM) grid-scale storage was deployed in India across seven projects as of March 2021. By the end of last year, projects that had reached financial close and were in the construction phase reached 360MW/312MWh.

However, despite that growth many projects still face delays in implementation, due to factors like lack of financial support and the challenging nature of signing power purchase agreements (PPAs) with states.

Indeed, many Indian states appear reluctant to embrace energy storage despite their growing renewable energy capacity, and mandated targets for deployment would give drive and certainty to project development as well as to investments in manufacturing and other aspects of the energy storage industry ecosystem, IESA said.

A small handful of national and state governments around the world already have energy storage deployment targets such as Greece and Spain in Europe and 10 US states. A similar recent report from the European Association for Storage of Energy (EASE) found that Europe could need 600GW of storage by 2050.

In Australia, experts at the Victorian Energy Policy Centre (VEPC) have proposed that a A$20 billion fund to invest in renewable energy integration pledged by the country’s new government should use it to back an energy storage target policy.  

The full report can be downloaded from the IESA site, here.

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One of several solar projects in New York state that CS Energy partnered with Castillo Engineering on.

CS Energy, Castillo Engineering and Amp Energy are delivering a portfolio of 25.4 MW of community solar projects in upstate New York. Ranging from 3.9 MW to 6.2 MW in size, all five projects will utilize bifacial modules mounted on fixed tilt racking and are part of the local utility’s community solar program.

“We are excited to be able to work alongside CS Energy on this portfolio of projects, given their leadership in New York, diversified labor base, and competitive pricing, even despite current market conditions,” states Kevin Foster, director of U.S. projects at Amp Energy. “Through this partnership, we will be able to deliver more affordable clean energy to local communities throughout New York state, while also contributing to the state’s ambitious renewable portfolio standards.”

Four of the projects are currently under construction, with the fifth project expected to commence construction this month. All five projects are expected to achieve commercial operation by Q4 2022.

“Amp Energy is a global leader in distributed renewable energy generation, and we are looking forward to working alongside their team as we further expand our presence and megawatts put in place in New York state,” says Michael Garofalo, vice president of operations at CS Energy. “Castillo Engineering also continues to be a reliable, flexible and customer centric Engineer of Record, with a great deal of experience in this region, as we are pleased to be able to work closely with them on another set of impactful projects.”

“We are grateful to have again partnered with CS Energy due to our expertise in the New York market,” adds Christopher Castillo, CEO of Castillo Engineering. “This is our second portfolio of community solar projects in New York this year and we look forward to working further with CS Energy on additional projects in this region.”

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Industria Power’s installed BESS system at the San Pasqual Band tribal centre. Image: Industria Power.

Investor-owned utility SDG&E and the City of San Diego are launching a dozen microgrid projects with energy storage across San Diego, California, following similar announcements elsewhere in the state.

San Diego Gas & Electric (SDG&E) received approval on June 24 from the California Public Utilities Commission (CPUC) to build four microgrid projects at existing substations in the San Diego region, with a combined 39MW/180MWh of energy storage capacity.

The units will help the state of California meet high energy demand, particularly on hot summer days and during peak demand evening hours when solar generation is low. They will be able to operate independently or in parallel with the larger regional grid ensuring critical community facilities remain powered during grid-level outages.

The projects are called Clairemont, Boulevard, Paradise and Elliott and will all have the ability to power a range of public facilities like schools, fire and police stations, post offices and healthcare facilities across the city. They are set to be completed by summer 2023.

Microgrid projects like SDG&E’s stem from governor Gavin Newsom’s proclamation of a State Emergency issued last summer which set out actions to expedite clean energy projects to ensure the state was better-placed for summer 2022 and beyond. This included battery storage systems of 20MW or more with two-hour-plus durations with certain permitting and licensing requirements effectively waived.

“These clean energy projects will help our region become more resilient to the impacts of our worsening climate,” said SDG&E Vice President of Energy Innovation Miguel Romero.

Gridscape and Shell bring in contractor for eight microgrids

On the same day as the CPUC’s approval for SDG&E’s four microgrid projects, the City of San Diego awarded developer and contractor Industria Power a construction contract for eight microgrids. The project developer is Gridscape Solutions, on behalf of the City, while Shell New Energies US will be the asset owner and operator for 25 years.

The City of San Diego prioritised eight building sites, including three recreation centres, two fire stations and three police stations.

Each will get self-contained power systems with onsite renewable energy generation and storage that will also provide backup power for the community during public safety power shut off (PSPS) events or other outages, provide access to EV charging stations and save the City an estimated US$6 million in energy costs over 25 years. It was reported last year that Shell expected to spend US$4 million on the project.

The deployments which will help the city meet its goal of reducing electricity use by 25% from 2010 levels, by enabling dynamic shifting of the facility’s energy load by optimising electricity consumption and demand in response to grid signals and energy pricing.

A press release said the microgrids will include 930kW of solar PV systems. It added that storage component will comprise “2,175MWh of battery storage”, although earlier reports and the disclosed investment sums indicate this is an error and much more likely to be a kWh number. Energy-Storage.news has asked Industria Power’s media contact to confirm this and will update the story in due course.

A microgrid that Gridscape and Industria recently commissioned at the San Pasqual Tribal Hall, just outside the city of San Diego (pictured), combined 156kW of solar PV with 480kWh of battery storage. It appears unrelated to the eight Industria has been awarded by the City of San Diego but gives an idea of the size of system the groups have been deploying.

Gridscape describes itself as a smart energy solutions company and said it plans to deploy and operate over 35 microgrids in California over the next 12 months.

Microgrid projects: a growing trend in The Golden State

Microgrids with energy storage have been deployed elsewhere in California recently for a variety of critical facilities, covered by Energy-Storage.news.

A notable example was a front-of-meter microgrid combining 2.2MW of solar PV with a 9MWh battery went online a few weeks ago in Humboldt County, northeast California. Its developers claimed it is is the first 100% renewable energy, front-of-meter, multi-customer microgrid to go online in the state, and will provide backup power to two airports plus other facilities.

In May, Solano County partnered with Engie North America, part of the French utility, to install four microgrids with solar and storage for a total investment of US$41 million, which will also include 54 EV charging stations. The estimated energy bill offset over 20 years is US$60 million.

The same month, water utility Santa Margarita Water District engaged Scale Microgrid Solutions to install, finance and operate a 1MWh energy storage system at its water and wastewater treatment facilities in the Santa Lucia Mountains. It will pair with an existing 1MW solar PV and enable eight hours of backup power in case of a grid outage.

All customers within the service area of SDG&E’s fellow investor-owned utility PG&E have been eligible to apply for support to install renewable-plus-storage microgrids, as of December 2021.

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LG and Fractal EMS shake hands on the deal. Image: LG.

LG Electronics has chosen an energy management system (EMS) developed by Texas company Fractal EMS for commercial and industrial (C&I) energy storage systems in the US market.

LG said on Friday that it has also invested an undisclosed amount into Fractal EMS, which it considers a strategic investment.

The electronics subsidiary of South Korea’s LG Group holding company also makes and markets battery storage systems through another division, LG Energy Solution, as well as battery cells through LG Chem.

Its products for C&I users currently enable three major applications: peak shaving (reducing draw of power from the grid at peak times to lower electricity costs), increasing onsite consumption of renewable energy and back up power.

At an event last year hosted by our publisher Solar Media, the US C&I market was described as being “extremely lucrative” by a panel of industry experts and participants.

However, in most parts of the US, the business case for distributed energy resources (DERs), which include C&I as well as home battery storage systems, looks set to be further and greatly boosted by the introduction of FERC Order 841 and Order 2222.

Through these, the Federal Energy Regulatory Commission (FERC) has instructed regional transmission organisations (RTOs) and independent system operators (ISOs) to reconfigure their wholesale markets to enable full participation of energy storage (Order 841) and DERs (Order 2222).

Efforts to create and integrate these rules are ongoing and at different pace in different RTO and ISO jurisdictions that are covered by FERC.

Fractal EMS meanwhile describes its EMS as a turnkey control system for energy storage as well as for other DERs. The package includes hardware, software, integration, monitoring and servicing and can be used to command, control, manage and monitor systems at individual or fleet level.

A separate line of the business, Fractal Energy Storage Consultants, assists clients with everything from project design and due diligence to witnessing and verification of site acceptance testing to operations, maintenance and monitoring and many other stages of their project.

Energy-Storage.news enquired as to whether LG will be also working with the consultancy, but had not received a reply at time of publication.

Fractal EMS has been used at 3GWh of energy storage projects worldwide already and the company claims a pipeline of a further 8GWh of awarded energy storage system (ESS) and hybrid projects using ESS.

LG Electronics also offers a full suite of other buildings electrification technologies, including heat pumps and HVAC. The company’s North America president and CEO Thomas Yoon said Fractal EMS’ tech and LG’s ESS can be part of an “energy ecosystem for high-performance buildings”.

LG pointed out that it is also set to launch a new range of home energy storage systems this year.

“LG’s investment advances our mission to combine modern architecture and competitive pricing to create the industry’s best energy storage and hybrid controls,” Fractal EMS CEO Daniel Crotzer said, adding that the integration of the two companies’ products “will contribute significantly to the industry’s efforts related to maximising safety and profitability of storage and hybrid systems”.  

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