Most of Italy’s battery energy storage deployments to-date have been in the residential sector, but large-scale systems connected to the country’s grid, operated by Terna, are set to come online in the next few years. Image: Terna.

Recently-formed developer Innovo Group is targeting a 1.5GW/9GWh lithium-ion BESS development portfolio in Italy and UK, with the first system in central Italy online in Q1 2024.

CEO Rodolfo Bigolin announced the start of development of the 72MW/432MWh BESS in central Italy via Twitter last week (9 November), saying the system would provide fundamental support for the deployment of renewable energy in Italy.

Bigolin told Energy-Storage.news the project should come online in quarter one, 2024. He added that the firm expects to bring three more projects totalling 150MW/900MWh through grid studies (STMD) application by the end of this year and a further 500MW/3,000MWh by end-2023. STMD stands for Soluzione Tecnica Minima di Dettaglio (Minimum Detail Technical Solution).

The firm plans to have a 1.5GW/9GWh – six-hour duration – portfolio of BESS under development in all geographies including the UK by quarter one of next year.

“Innovo is working with leading EPCs, Operators and Technical advisors in the Italian and Global markets to explore critical issues today and define a future market roadmap as accurately as possible,” he said.

Discussing the announced Italian project, Innovo’s engineering director Stefano Girolami said: “Our 72MW project is located in Abruzzo, an area that we expect to be strategic from a nodal and grid overloading point of view, with solid renewable generation in the Southern Adriatic areas and dispatch to the northern Italian regions. For this reason, battery storage in these areas will facilitate grid balancing.”

“As explained above, we opted for a medium size, given the presence of medium-sized grid substations of strategic importance.”

The company has chosen to move to a six-hour duration for its projects because the battery storage market is becoming increasingly energy-intensive rather than power-intensive, Girolami added, alluding to the move in most developed markets to energy trading rather than just providing frequency response services.

Despite the longer duration, the company considers lithium-ion the most viable chemistry on the market for the projects, with Girolami citing modularity, high-efficiency and high-density as the things that make it most attractive.

“If and when, new solutions will be available at competitive cost and large-scale availability, we will definitely consider them. Improvements can and need to be made in terms of degradation levels and sustainability related to lithium-ion technologies,” he added.

He added that the falling cost of implementing battery storage projects will make it possible to build business models on subsidy-free, pure ‘merchant’ revenue streams, as opposed to stacking grid services with auctions and day-ahead markets. Grid operator Terna is requesting discharge durations of up to eight hours in auctions covering the next three to five years.

Girolami said the higher duration also allowed the firm to maximise its footprint and future-proof the system.

“We also tend to maximise energy to maximise the footprint, giving us more flexibility in the permitting phase and future management of the system (energy increases, battery replacement etc., to keep the efficiency of the BESS as high as possible throughout its lifecycle).”

“The battery storage market is developing fast, and future connection volumes of renewable energy (intermittent) to the Italian RTN (national transmission grid) will make this service indispensable.”

Italy has around a gigwatt of BESS installed – 1,200MWh by Q1 2022 according to national renewables association, ANIE Rinnovabili, and around 900MW by end-2022 according to research firm Delta-EE.

The vast majority of that is residential/distributed energy resources (DERs), largely thanks to the ‘superbonus’ incentive for homeowners, but the country is set to rapidly increase its utility-scale deployments over the coming years. Delta-EE is forecasting around 800MW of front-of-meter deployments in both 2023 and 2024.

Durations appear to have moved far beyond one or two hours, which still prevails in the UK market, Europe’s biggest.

Battery storage assets are increasingly winning in Italy’s capacity market auctions and renewable energy deployments are starting to pick up year-on-year, as reported by our sister site PV Tech, which will increase intermittency and therefore arbitrage opportunities for BESS projects.

Discharge durations of four-hours as seen in huge recent projects from Ingeteam and Nidec Group, and now six hour ones from Innovo, should come as no surprise.

Bigolin announced the formation of Innovo Group earlier this year as a consolidation of various renewable energy ventures launched in the UK and Italy.

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Aerial shot of H2’s factory under construction. Image: Shin Han via LinkedIn.

H2 Inc, a South Korean vanadium flow battery company, has begun construction of a factory with 330MWh annual manufacturing capacity.

Scheduled to become operational next year, the production plant’s construction in the city of Gyeryong-si was announced yesterday, by H2 Inc founder and CEO Shin Han on social media networking site LinkedIn.

The company has developed Enerflow, a vanadium redox flow battery (VRFB) based on proprietary technology, claiming that a high level of vertical integration will make its products affordable for large-scale, long-duration energy storage (LDES) applications.

In October last year, H2 raised US$15 million in a Series B funding round, bringing its total funding raised to US$38 million.

Then, in December, the company announced that it is building a 5MW/20MWh project in California, which by megawatt-hours would be the biggest VRFB project in the US to date – although bigger projects are planned to supersede it.

The US’ current largest vanadium flow battery project, also in California, is a 2MW/8MWh demonstration project in the service area of utility SDG&E. In fact, as the first US state to introduce legislation to support LDES deployment, California appears likely to be the first major market in the country for VRFBs and other LDES technologies.

A community energy organisation, Central Coast Community Energy is contracting for three flow battery projects including one of 16MW/128MWh, expected to be operational in 2026.

ESS Inc, a manufacturer of flow batteries using a different electrolyte based on iron and saltwater as opposed to vanadium, recently scored a deal with California energy supplier SMUD for up to 200MW/2GWh of its systems.

On a related note, the California Energy Commission (CEC) just made its first payout from a US$380 million fund to support LDES, committing US$31 million funding for a microgrid project that will pair a 1MW/10MWh VRFB with a 35MWh zinc hybrid cathode battery storage system.

Shin Han of H2 said the company’s California project will be “the first noteworthy” VRFB system manufactured at the Gyeryong-si plant.

The CEO added that an important part of H2 Inc’s strategy is to market VRFBs as a fire-safe alternative to lithium-ion batteries, referring to 37 documented fires at Korean battery storage facilities within the past five years.

H2 Inc’s is the latest in a series of vanadium flow battery factory announcements, as well as announcements around raw materials extraction and processing and electrolyte manufacturing to feed those factories.

Most recently, plans for a possible VRFB gigafactory in Saudi Arabia were revealed by Indian flow battery company Delectrik and its Saudi partner, Tdafoq earlier this month. In October, Japanese energy company Idemitsu invested into a vanadium extraction plant in Australia, with various entities looking to establish extraction, electrolyte production and manufacturing capabilities in the country.

Access to vanadium and electrolyte to make finished products with may be the key limiting factor for VRFBs once market demand picks up.   

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Following the collaboration agreement signed between SolarDuck and RWE in July of 2022, RWE has selected SolarDuck as the exclusive provider for offshore floating solar (OFS) technology with integrated energy storage in RWE’s bid for the Hollandse Kust West (HKW) VII offshore wind farm. The successful bid will now materialize a hybrid OFS power plant at scale. SolarDuck will build a 5MW demonstrator with innovative integrated energy storage solutions.

“This is a flagship project for SolarDuck and an important milestone for the wider OFS industry,” states SolarDuck´s CEO Koen Burgers. “SolarDuck, being the first to build a hybrid project at this scale, will demonstrate the robustness of our solution, prove the important role of system integration in building future-fit energy systems, and enable the scaling of the technology to accelerate its adoption. We are proud to work together with our partner, RWE, in this important project.”

SolarDuck, a Dutch-Norwegian OFS company, generates offshore solar energy using its state-of-the-art technology.

The HKW VII wind farm is one of two wind farms due to become operational by 2026 with a capacity of 700 MW. The wind farm is located approximately 28.6 nautical miles (53 kilometers) off the west coast of the Netherlands. In addition to the production of offshore wind energy, the government requested participating parties to offer solutions for fully integrating all the electricity generated into the Dutch energy system with the goal to contribute to the goal of 21GW of offshore wind energy around 2030.

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Laura Deehan

The California Public Utilities Commission (CPUC) has issued a proposed decision that, if finalized, will dramatically change how owners of rooftop solar in the state get compensated for the energy they provide to the electric grid, according to Environment California.

After proposing controversial changes to the state’s landmark rooftop solar program in December 2021, the CPUC faced public backlash, reopened discussion on the proposed changes and has now updated its proposal. CPUC’s revision addresses numerous critiques raised by Environment California in response to previous drafts.

The new proposed draft eliminates the solar tax, or “grid participation fee,” that the previous proposal would have implemented on solar consumers. It honors the commitment to pay current rates to existing solar energy system owners who send excess power they generate to the grid. On the down side, the proposed decision slashes the rate at which new solar consumers can sell their excess electricity back to the grid by 70-80%, reducing a key incentive for people to install solar in their homes and recoup their investment within a reasonable time frame.

California produces more solar energy than any state in the nation, but to meet its ambitious climate and clean energy goals, including generating 100% of its power from clean energy sources by 2045, California needs to quadruple its rooftop solar capacity, states Environment California.

Oral arguments will take place at CPUC and a final vote scheduled for December 15.

“At a time when California needs rooftop solar to flourish, it’s risky to cut a key incentive without having a viable alternative in place,” says Environment California State Director Laura Deehan. “California’s decision-makers need to make rooftop solar as affordable and accessible as possible so that every household with solar potential can realistically make the choice to go solar. While the revised proposal eliminates the solar tax and protects current solar customers, it will make transitioning to solar power more expensive.”

“If we want to protect the environment, our climate and our health, we must keep rooftop solar growing and continue incentivizing the growth of clean, renewable energy across California,” Deehan adds.

Environment America, a part of The Public Interest Network, is a national network of 30 state environmental groups.

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Used Chevrolet EV batteries provide stationary energy storage at a GM Enterprise Data Center. Image: John F. Martin for General Motors.

General Motors (GM) is partnering with one of California’s main investor-owned utilities (IOUs) to explore the potential of vehicle-to-grid and vehicle-to-home battery integration.

Utility San Diego Gas & Electric (SDG&E), which serves 3.7 million people, announced the pair’s collaboration yesterday.

They will investigate the feasibility of integrating bi-directional electric vehicles (EVs) to act as an energy resource for the grid. That includes looking at the various considerations for hardware, software, processes and construction required to enable vehicle-to-grid (V2G), where energy stored in vehicles can be leveraged for the network.

It closely follows the launch by carmaker GM last month of a dedicated energy storage division, called GM Energy. GM Energy is offering products to the residential and commercial and industrial (C&I) battery storage market segments, along with EV charging, powered with lithium battery cells from Ultium, the company’s joint venture (JV) with LG.

General Motors and SDG&E will look into three different capabilities of vehicle integration: V2G, vehicle-to-home (V2H) and virtual power plants (VPPs). They want to create best practice guides for customers, develop systems that will allow utilities and vehicle manufacturers to leverage aggregated fleets of vehicle batteries, and explore the use of bi-directional EVs in resilient microgrids.

Powerful potential

The collaboration comes amid a wave of exploratory and pilot activity in the vehicle-to-x sector. Pacific Gas & Electric (PG&E), another of California’s IOUs, recently established the US’ first dynamic export mechanism for commercial vehicle V2G charging.

With California a rapid early adopter of EVs, PG&E claimed its service area accounts for one in six EVs in the entire country, with about 420,000 on the roads. The state has also banned the sale of new internal combustion engine (ICE) cars by 2035.

Earlier this month, a community microgrid went online in Arlington, Washington, which includes V2G charging stations. The renewable energy microgrid will use a combination of a 1MW/1.4MWh lithium-ion battery energy storage system (BESS) with two V2G chargers.

The utility behind that microgrid project, Snohomish County PUD, is using Nissan Leaf EVs, which at present is the only widely used consumer EV in the US market with bi-directional capabilities enabled.

V2G could become a powerful resource. US residential solar and storage provider Sunrun launched a partnership with Ford earlier this year, through which Sunrun’s EV bi-directional charging equipment can be used with the carmaker’s new all-electric F150 truck.

At the moment, the Sunrun-Ford tie-up only covers V2H, so that homeowners can use the truck’s battery – 130kWh in the long-range model – for backup power if the grid goes down. However, the pair have made it V2G-ready too.

In an interview published yesterday, Sunrun policy and markets VP Chris Rauscher highlighted that during California’s September heatwaves, about 2,000MW of demand response and distributed energy resources (DERs) were called upon to balance the grid’s mismatch between supply and demand.

“We’ve done the modelling that shows that’s only 200,000 F150 Lightnings that could have provided that. It sounds like a lot, but Ford sold 125,000 internal combustion F150s last year in Texas alone,” Rauscher said.

“They sold around 850,000 nationwide, so it’s really not that many trucks that would have been able to keep the California grid up, and those trucks could have done that for 13 hours.”

A few days ago, V2G technology specialist The Mobility House closed a US$50 million funding round. The Germany-headquartered company is active in various markets and in August said that it would be trading 100MW of V2G power on European electricity spot markets. Also in Europe, a subsidiary of Volkswagen recently formed a V2G partnership with transmission system operator Elia Group, in Germany.

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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WA energy minister Bill Johnston (second from left) with other project partners last week. Image: Synergy.

A virtual power plant (VPP) has gone live in Western Australia, aimed at showing how hundreds of distributed energy resources can help stabilise the electricity grid.

Called Project Symphony, the two-year pilot project is being conducted by state-owned electricity network provider Western Power, utility company Synergy and the Australian Energy Market Operator (AEMO).

AEMO announced last week that more than 300 customers and more than 650 customer-owned distributed energy resources (DERs) have been recruited to take part, and technology platforms have been built for their DERs to be integrated into.

The project will now begin a period of scenario testing. AEMO will serve as market and system operator, Synergy as aggregator and Western Power as distribution network service operator.

The target is to enroll up to 900 DERs at around 500 homes and businesses.

Essentially, as reported by Energy-Storage.news last December as details of the pilot were revealed, Project Symphony is in an area of particularly high rooftop solar adoption, in a country of high rooftop solar adoption.

The Western Australia power grid was not designed for the two-way flow of electricity that comes with the shift to distributed and renewable energy. A third of WA homes have solar PV, and in the areas of Harrisdale and Piara Waters where the project is taking place, it’s more than 50%.

By “orchestrating” assets like solar, home battery energy storage systems and some household appliances like smart thermostats, the VPP coordinates the generation and storage of electricity at a local level.

“This is the first time ever in the Perth metropolitan area, that customer-owned energy resources including rooftop solar and batteries have been ‘orchestrated’ to test their ability in addressing system stability challenges, as we transition to a lower cost renewable energy future,” AEMO executive general manager for WA and strategy Kate Ryan said.

In other words, the VPP responds to grid conditions in real-time, managing the flow of electricity around peak and off-peak periods. Enabling DERs to be integrated more efficiently into the grid, the project should lower system costs for consumers and free up more capacity for renewable energy to be carried on the network.

Project Symphony will test out four different scenarios in the scenario testing phase. These include a simulated local wholesale electricity market in which more than 200 DER assets will act as one resource, meaning the virtual power plant can bid and dispatch into the market while also providing voltage services to the network.

The project is costing around AU$35.5 million (US$23.6 million), with testing scenarios to continue to April 2023 and key outcomes to be published before the end of 2023.

Funding has come from the Western Australian government, the Australian Renewable Energy Agency (ARENA) and AEMO. The project is a key part of the state government’s Distributed Energy Resources Roadmap strategy for energy transition.

Virtual power plants are springing up around the world in different configurations. Australia’s largest to date is in South Australia, which completed its first trial phase in 2019, equipping 1,100 social housing properties with solar and battery storage. The South Australia VPP is now in its third phase with more than 3,000 participating properties, with aims to eventually reach 50,000 connected homes.

“It’s great to see hundreds of customers embracing Project Symphony. Their participation will provide valuable insights into how Western Australia’s electricity system can be strengthened to continue to provide reliable, secure, and affordable power,” Western Australia’s energy minister Bill Johnston said.

“In the face of a rapidly changing energy industry, customers’ rooftop solar systems, batteries, and air conditioning orchestrated together can play a meaningful role in providing services and stability to the network.”

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Killian McKenna

Every day, utilities across the country receive applications from customers requesting to connect their rooftop solar systems to the grid – up to hundreds per day and thousands per week. This high volume of interconnection requests shows no signs of slowing down as the price of photovoltaic (PV) systems decrease and states and local governments set higher renewable energy goals for their communities.

This swell in solar interconnection requests has created a new challenge for utilities because each application received requires a technical evaluation to assess the potential grid impacts of the new solar installation. This technical assessment evaluates impacts to power quality and infrastructure assets and is a key element of a utility’s interconnection approval process. Right now, utilities are evaluating interconnection applications manually, which means there is an increasing demand on already burdened distribution engineers.

To manage the growing volume of requests, utilities are increasingly turning to hosting capacity analysis to provide public visibility into the capacity of their networks to accommodate solar. The resulting hosting capacity maps provide a broad snapshot for customers to know if their local grid can accommodate—or host—new solar generation. These maps, although useful for high-level planning, still do not answer the question of whether individual solar applications can interconnect to the grid, as every interconnection can trigger unique local distribution system constraints.

Grid researchers at the National Renewable Energy Laboratory (NREL) have partnered with the Sacramento Municipal Utility District (SMUD) to solve that pain point in the interconnection process.

“Our project team set out to understand how a utility can assess solar applications in a fast, robust fashion while still being technically thorough,” says Killian McKenna, a senior researcher in NREL’s Grid Planning and Analysis Center and the principal investigator on the effort.

Their solution was PRECISE – PREconfiguring and Controlling Inverter SEt-points – a tool that performs fast and automated interconnection assessments and seamlessly integrates with SMUD’s existing business interconnection workflow.

“PV interconnection evaluation is becoming a time-consuming process as each proposed solar power system must be individually reviewed in detail to make sure it works safely with our grid,” states Sheikh Hassan, a principal distribution engineer at SMUD. “PRECISE significantly reduces this evaluation time by instantly determining optimal inverter settings for a given location.”

PRECISE went live at SMUD on Feb. 26, 2022, and has processed over 1,700 applications in its first six months of operation, an average of 13 applications each business day and as many as nearly 30 applications in one day. The tool itself can scale to process any number of applications; through automation, data integration, and fast computing techniques, PRECISE can easily handle hundreds of applications daily.

“This is a tremendous result for our team and has ensured staff gets the help they need while speeding up the interconnection process and lowering costs for our customers,” comments Sruthi Nadimpalli, an information technology (IT) project manager with SMUD. This functionality won PRECISE an R&D 100 Award in 2019, has helped customers safely and efficiently install more solar energy in SMUD’s service areas, and has worldwide potential.

Automating this workflow is complicated. To be technically rigorous, PRECISE automates the modeling of all of SMUD’s 40,000-plus distribution secondaries – or the low-voltage distribution system connected to houses and rooftop solar – and pulls in advanced metering infrastructure (AMI) data as required. The tool also uses local irradiance measurements across SMUD’s service area and creates mathematical models of each incoming PV system. This involves modeling every component of the solar panels and their orientations, as well as the inverters and smart inverter capabilities, to make the assessment.

The whole process is automated to ensure that PRECISE pulls in data as soon as a customer’s interconnection application is created and updates business teams downstream (i.e., planning, metering, line design) once its calculations are complete, creating a streamlined solar interconnection process tailored to fit SMUD’s unique local needs.

One common scenario for SMUD customers involves requests to interconnect solar power systems larger than the grid could accommodate in a specific location. PRECISE automates an assessment of what size system the grid can accommodate and how advanced inverter functions can support approval. In these scenarios, planning engineers have this information and can work with the customer to find a solution to enable the PV system to interconnect successfully.

For every residential solar PV interconnection application, PRECISE assesses the impact of the interconnection proposal and evaluates the need to use smart inverter functions.

“The task to determine optimal smart inverter settings in order to maximize our PV hosting capacity will become more complex and time intensive as the number of PV interconnection applications increase,” Hassan adds. Smart inverter functions can be the deciding factor on whether an interconnection must be downsized or not, and PRECISE enables that evaluation, leveraging inverter functions as needed, to help accommodate more solar onto the grid.

To make PRECISE happen, NREL worked closely with a SMUD team that included more than 20 personnel working over multiple departments at the utility – including geographical information system (GIS) experts, advanced metering infrastructure leads, distribution engineers, database administrators, application administrators, information technology project managers and business process experts.

NREL’s project team included Kapil Duwadi, who played the role of application developer, Aadil Latif, who automated the modeling of SMUD’s entire distribution system, and Killian McKenna, who oversaw the effort.

Close collaboration between NREL engineers and a diverse SMUD team was vital to the successful integration and automation of PRECISE. The project was the first automation of the technical interconnection evaluation process of its kind, one that could serve as a template for many utilities that wish to automate the increasing challenge of evaluating new interconnection requests.

“PRECISE is a cutting-edge PV interconnection evaluation tool that enables utilities to cost-effectively host more solar,” Hassan says.

Given this achievement, NREL and SMUD are exploring future collaborations together, now that PRECISE has linked the diverse utility data sets (e.g., meter data, GIS, interconnection applications) needed for automated evaluation of new distributed energy resources. PRECISE could now be applied to large commercial solar sites, to assess battery energy storage, or to evaluate the impact of electric vehicles as they connect to the grid.

“The future for grid planning and operations is increased automation for evaluating the health, impacts, and opportunities of increasing levels of distributed energy resources,” McKenna mentions. “PRECISE is a first step of many to reach that future.”

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Kyle Udseth

Pineapple Energy Inc., a provider of sustainable solar energy and back-up power to households and small businesses, has acquired SUNation Energy, a New York-based installer of solar and battery energy storage systems for residential and small commercial customers. Over the course of almost 8,000 projects since inception, SUNation has installed over 275,000 solar panels representing 92 MW of clean, carbon-free solar power.

Founder Scott Maskin will continue to manage SUNation in New York. He will engage current and future acquisitions in core value alignment and be appointed to Pineapple’s board of directors. SUNation’s Chief Growth Officer Jim Brennan will move into a strategic role at Pineapple Energy, leading the corporate development function, where he will help execute the strategic vision for both organic and M&A-driven growth.

“We’re thrilled to announce the SUNation acquisition, which is a fantastic complement to our Hawaii Energy Connection and E-Gear acquisitions which closed alongside our merger into a publicly traded company earlier this year,” says Kyle Udseth, CEO of Pineapple Energy. “This acquisition is an indication of the growth potential inherent in our strategy of consolidating and building a nationwide solar, battery storage and home energy management business.”

“We believe the acquisition will give us more scale, increase our revenue substantially, and move us toward achieving the important goal of reaching cash flow positive in 2023,” continues Udseth. “Further, it expands our footprint into the northeastern United States, a region with strong demand for solar energy. We’re excited to welcome the SUNation team to the Pineapple family and look forward to growing our business as an integrated team.”

“SUNation Energy is elated to join the Pineapple Energy family,” states Maskin, SUNation’s founder, CEO and chief fun officer. “Almost 20 years ago we set out to change the way our friends and neighbors powered their homes and businesses. Through the years we’ve seen many companies come and go, mostly because they forgot who was most important, the customer. We are so fortunate to find a team that shares the same core values and goals as SUNation.”

“Dominant, high quality, referral based regional companies are the heart and soul of this industry and Pineapple was quick to recognize the amazing work the SUNation team has accomplished,” adds Maskin. “Together with the Pineapple team, we can scale this model nationally while delivering the highest quality customer experience possible The Pineapple team is humble, knowledgeable and aggressive. We are an unstoppable team.”

“SUNation moves us closer to the critical mass we need to accelerate our growth,” Pineapple CFO Eric Ingvaldson expands on the financial and strategic rationale. “They generated revenue of $48 million in the trailing twelve months ended September 30, 2022, which represents approximately twice the revenue generated by our Hawaii operations. In addition, we are continuing to focus on other acquisition opportunities. We are excited about the potential to enter 2023 with strong business momentum, a growing national footprint, an outstanding team with extensive solar industry knowledge, and positioned to become cash-generating during the year.”

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A DSD installation in New York

DSD Renewables (DSD) has secured a $40 million tax equity investment from U.S. Bank to support its 2022 and 2023 build plans.

The financing will fund a 45 MW portfolio consisting of a mix of community solar, power purchase agreement and feed-in-tariff projects. About half of the projects are located in New York, with the remaining projects scattered across Connecticut, Maine, Maryland, Minnesota, New Jersey and Virginia.

By the end of the year, DSD will have raised over $1.5 billion in funding to accelerate solar project deployment in 22 states.

“This tax equity investment will help DSD optimize value for many key projects under development and enable us to continue supporting the energy transition across the U.S.,” says Hannah McGovern, DSD’s VP of structured finance. “We are excited to be partnering with U.S. Bank and look forward to expanding our work together in the future.”

The tax equity financing represents DSD’s first transaction with U.S. Bank, which commits $1 billion annually to renewable energy investments and has set a goal to achieve net zero greenhouse gas emissions by 2050.

McDermott Will & Emery LLP served as counsel to DSD on the transaction.

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Semtech Corp., a global supplier of high-performance analog and mixed-signal semiconductors and advanced algorithms, is collaborating with Exeger, a deep-tech company manufacturing fully customizable solar cells. Combining Semtech’s LoRa Edge asset management platform with Exeger’s Powerfoyle solar cell technology significantly extends the battery life of asset tracking and environmental sensing devices.

Semtech’s LoRa Edge scans GNSS satellites as well as Wi-Fi SSIDs and partitions the processing between IoT devices and the LoRa Cloud to determine location. The cloud-based solver significantly reduces power consumption and increases battery life. Exeger’s Powerfoyle is uniquely flexible and durable and can be integrated seamlessly into any electronics device. The solar cell technology converts all forms of light to charge and power devices with clean, endless energy.

“Coupling the benefits of Powerfoyle with the ultra-low power capabilities of Semtech’s LoRa devices will provide IoT applications with an extended or even unlimited battery life,” says Dr. Oscar Hemberg, chief product integration officer at Exeger. “Together, we move one step closer to energy independence through more sustainable products powered with clean, endless energy.”

The patented Powerfoyle material integrates into IoT sensors with Semtech’s LoRa Edge chip-to-Cloud platform with the goal to create a new standard for environmentally friendly platforms for the IoT industry. Combining both technologies is expected to spur a world of new solar-powered tracking applications for geolocation use cases, including indoor and outdoor asset tracking, global supply chain logistics, agriculture, smart utilities, and smart cities.

“LoRa devices enable smart IoT applications that help solve some of the biggest challenges facing our planet,” states Marc Pégulu, vice president and general manager for Semtech’s Wireless and Sensing Products Group. “Semtech and Exeger’s collaboration will enable manufacturers to develop IoT devices leveraging new energy harvesting technology for a smarter and more sustainable future.”

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