Ormat Technologies Inc., a renewable energy company, and San Diego Community Power (SDCP), California’s second largest community choice aggregator, have signed a power purchase agreement (PPA) for the Arrowleaf Solar and Storage Facility. The venture will bring clean, renewable, affordable energy to the nearly 1 million customers of SDCP.

The Arrowleaf Solar and Storage Facility is located in Imperial County, Calif., adjacent to Ormat’s operational Brawley geothermal facility and within the Imperial Irrigation District (IID) service territory. Under the terms of the 20-year deal, Ormat will provide SDCP with sustainable electricity generated by the Arrowleaf Solar and Storage Facility at predictable rates for customers.

“San Diego Community Power’s mission is to provide clean, reliable, and affordable energy to our customers across the region,” says San Diego City Councilmember Joe LaCava, chair of San Diego Community Power. “The Arrowleaf Solar and Storage project will be a critical component to ensure that, not only are we meeting our ambitious renewable goals, but we are creating quality construction jobs that support the energy transition in our communities.”

The solar component of the project will contribute 42 MW of clean energy to the grid – enough to power approximately 31,500 homes. The project’s storage component will provide 35 MW/140 MWh of capacity, which is enough to provide 4 hours of electricity during peak consumption periods when solar is not operating.

“We are proud to contribute to and facilitate SDCP’s mission,” says Doron Blachar, CEO of Ormat Technologies. “Ormat remains dedicated to developing innovative renewable energy solutions, supporting the goals of its customers and partners, and further demonstrating our leading capabilities in the fields of geothermal power production and energy storage services.”

The battery technology that will be used for the Arrowleaf storage facility has been successfully procured from a leading global supplier at an attractive purchase price and is expected to reduce the overall costs to develop the storage assets and further enhance the return profile of Ormat’s growth investment in the complex. Operations are expected to commence in the first half of 2025.

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Capital Power has secured its first order of approximately 1 GW DC of ultra-low carbon thin-film solar modules from First Solar Inc. The Series 6 Plus modules, which will be delivered between 2026 and 2028, will support Capital Power’s growing development portfolio.

“First Solar’s longstanding investment in domestic supply chains ensures the use of high-quality American solar technology, including products made with significant amounts of domestically sourced content, to power our projects,” says Chris Kopecky, senior vice president of Capital Power. “Together, with our shared commitment to the sustainable and responsible development of the solar industry, we look forward to building on this relationship.”

First Solar’s responsibly produced, advanced thin-film photovoltaic (PV) modules have the lowest carbon and water footprint of any commercially available PV module today. It’s also the first PV manufacturer to have its product included in the Electronic Product Environmental Assessment Tool (EPEAT) global registry for sustainable electronics.

Of the world’s ten largest solar manufacturers, First Solar is the only one that is a member of the Responsible Business Alliance (RBA), the world’s largest industry coalition dedicated to supporting the rights and well-being of workers and communities in the global supply chain. The company has zero tolerance for forced labor in its manufacturing or its supply chains.

The largest solar manufacturer in the Western Hemisphere, First Solar is investing approximately $1.3 billion in expanding its U.S. manufacturing footprint from over 6.5 GW DC of annual nameplate capacity currently, to approximately 10.9 GW DC by 2026.

Committed to net zero by 2045, Capital Power takes a balanced approach to power generation that includes a focused effort on solar energy growth across North America. With three solar facilities in operation, Capital Power will use its development and construction expertise to deliver projects against an active US solar pipeline totaling nearly 2.4 GWDC.

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Altus Power Inc., an independent developer, owner and operator of commercial-scale solar facilities, based in Stamford, Conn., has concluded the development and construction of a 4.8 MW ground-mounted solar array in Cayuga County, N.Y. Altus will own and operate the asset, which will generate clean electric power in support of New York’s community solar program, serving municipal and residential customers.

“Altus Power continues to grow its audience of community solar customers across the country,” says Lars Norell, Co-CEO of the company. “Our team is focused on turning newly constructed assets into operation and we continue to bring more assets into construction, many of them in support of community solar programs that make solar power at a discount an option for anyone who receives electricity from their local electric utility company.”

Altus Power provides commercial, industrial, public sector and community solar customers with end-to-end solutions. The Cayuga County array is part of 15 MW the company expects to complete across New York during 2023. New York is one of eight states where Altus Power serves or is currently constructing arrays to power community solar programs.

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Lynn Good

Duke Energy has reached an agreement to sell its commercial distributed generation business to an affiliate of ArcLight Capital Partners LLC, a middle-market infrastructure investor, for an enterprise value of $364 million, inclusive of non-controlling tax equity interests. Duke Energy expects approximately $259 million of proceeds from this transaction.

In early June, Duke Energy reached a sale agreement for its utility-scale renewables business platform. The company expects to finalize the sales for its utility-scale and distributed generation businesses by the end of 2023. It will utilize the proceeds to strengthen its balance sheet and avoid additional holding company debt issuances associated with these assets. These transactions will support Duke Energy’s focus on the growth of its regulated businesses, including investments to enhance grid reliability and help incorporate over 30,000 MW of regulated renewable energy onto its system by 2035.

“The sale of our commercial renewables businesses streamlines our portfolio and provides the resources to support the long-term needs of our customers in our growing regulated territories,” says Lynn Good, Duke Energy CEO, chair and president. “Over the next decade, we plan to invest significant amounts of capital to fund the critical energy infrastructure necessary to serve our customers and support our clean energy transition.”

The distributed generation business being sold includes REC Solar operating assets, development pipeline and O&M portfolio, as well as distributed fuel cell projects managed by Bloom Energy. Employees of the distributed generation business will transition to ArcLight to maintain business continuity for its operations and customers.

Adds Marco Gatti, managing director at ArcLight, about its acquisition: “We believe this is an attractive opportunity to acquire a first-rate commercial distributed generation portfolio, partner with a talented team and build upon long-standing, high-quality customer relationships.”

The sale is subject to satisfaction of customary closing conditions, including the expiration of the waiting period under the Hart-Scott-Rodino Act. Regulatory approval by the Federal Energy Regulatory Commission will also be required for the sale of the Bloom Energy distributed fuel cell assets.

BofA Securities, Inc. is serving as the financial advisor and Mayer Brown LLP is serving as the legal counsel to Duke Energy for this transaction. Scotia is serving as the financial advisor and Kirkland & Ellis is serving as the legal counsel to ArcLight.

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In Rioux’s current role, he leads development activities on a broad range of low carbon energy storage projects, from fleets of behind-the-meter residential batteries, to the 250MW/1,000MWh Oneida project that looks set to begin construction soon.

In the past, NRSTor has also worked in non-lithium technologies, including flywheels and the world’s first commercially operating advanced compressed air energy storage (A-CAES) plant.

But when working at Ontario Power Generation (OPG) – in which the main shareholder is the province’s government – Rioux worked across different technologies and business models in the thermal generation space.

That included the repowering of Ontario’s coal power stations to run instead on natural gas and biomass (considered one of the single biggest emissions reduction steps taken anywhere in North America), and developing new natural gas resources, among many other things.

One of the gas plants in OPG’s portfolio is the 550MW Portlands Energy Centre, a CA$730 million (US$549.5 million) facility on which Rioux led commercial activities including all gas and power trading.

Energy storage business models are increasingly moving towards being based on trading energy. While long-term contracts for battery energy storage system (BESS) and other storage technologies are still being signed in some markets, asset owners and operators are looking towards merchant revenue opportunities to either supplement, or even underpin, the revenue stack. Energy trading and arbitrage is likely to be a big part of that.

“There’s more parallels than you’d imagine. In fact, most [energy] storage projects, one of the larger values they deliver is capacity value, and capacity value comes gas-fired power plants, oil plants, coal plants, those types [of asset],” Rioux said.

“Capacity value doesn’t come from renewables typically because the renewables produce when Mother Nature provides it, and you can’t tell Mother Nature to act at a moment’s need. All of the services that energy storage provide to a grid or a utility, or even a large energy user, or a small energy user, have very strong parallels to the thermal fossil type assets that they’re replacing.”

An industry without inventory

We often hear that without energy storage, power generation for the grid is an industry without inventory, where supply and demand traditionally have had to be matched in real-time. In reality, shoring up natural gas supply to a power plant requires a lot of effort and a lot of cost.

Making long-term investments into new fossil fuel generation, whether gas or fuel oil, start to look less competitive when all of this is taken into account.

From his experience of shutting down coal plants to be replaced by gas for Ontario, Rioux said that while coal plants would have stockpiles of fuel onsite or nearby, gas plants do not.

“So there’s a huge energy storage investment that’s completely hidden, anytime you build a gas plant. You have to build gas storage somewhere and you have to build a pipeline network, to be able to flow your molecules of natural gas to your power plant exactly when you need it. That comes with a huge cost and it’s almost like you’re building two assets to get a capacity value.”

These would represent an asset investment with perhaps a 50-year or 100-year long-term outlook, and is also “not cheap” to do, Rioux said, with one of Ontario’s last new build gas plants paying roughly CA$50 million a year in gas service fees, for example.

“That’s not including the gas it burns, that’s just having space in the ground and space in pipes reserved for your use and no one else can use it, because you might need to use it in a moment’s notice. And gas trades on a daily basis. If you want to buy molecules of natural gas, and you want them for today, you have to buy them yesterday at 10 o’clock in the morning, that’s when the market trades.”

Natural gas is being used to help balance the integration of variable renewable energy (VRE) production from wind and solar, but this need for advance notice for energy trading makes it a less than ideal resource, especially when compared to dispatchable capacity from energy storage, Rioux argued.

In parts of the northeastern US, this need for inventory has seen some regions decide to instead put in oil tanks for storage and burn oil on days of highest peak demand.

“So basically, now you’re shutting down coal plants and building oil plants. You can see how it doesn’t make any sense to make long-term investments in those kinds of assets, and storage of all types, batteries, long-duration storage, whether it’s compressed air or pumped hydro, and various other technology types that are carbon-free, emissions-free; is a logical place to make our next big capital investments, as a world.”

Jason Rioux was among the interviewees in our recent look at the growth of energy storage in Canada’s two leading provinces, Ontario and Alberta, published in our quarterly journal PV Tech Power (Vol.35). You can read an extract of that piece on the site here, or read the full article with an Energy-Storage.news Premium subscription.

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The Bramley project is a joint venture between battery energy storage developer and operator Penso Power and investment platform operator BW ESS and is said to be the first BESS project within a broader pipeline in Bramley. BW ESS is the battery storage subsidiary of maritime company BW Group.

Once live in 2024, the project will support grid balancing, ancillary services and wholesale energy trading.

Sungrow will provide the project with an LFP-powered PowerTitan 2.0 liquid cooled BESS which has a power conversion system and battery integrated into a single 20ft container.

“Sungrow welcomes the opportunity to work with Penso Power and BW ESS on this important energy project for the UK. We previously collaborated with Penso Power on their 100 MW Minety battery energy storage system in 2019 and are proud to supply the new Bramley project – the first of several projects with 260MWh battery storage in the UK,” said James Wu, senior vice president at Sungrow.

“We look forward to collaborating further with Penso Power on their global project pipeline, including Australia and Italy.”

Penso won planning approval for the project, on appeal, in April this year.

To read the full version of this article go to Solar Power Portal.

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You can read about the basics of the project and their background, with a rapid construction timeline that began in September 2022, and how the developer is one among many to spot the opportunities at present and that lie ahead for batteries in Japan, in our news report from 27 June.

Below, we speak in further depth with Mahdi Behrangrad, head of energy storage at Pacifico Energy, for some details on key aspects of the projects, and what they might mean for the opening of the Japanese BESS market, which has been long awaited and appears to be warmly welcomed across the industry.

Behrangrad has been involved in the energy storage sector for close to 15 years, in a journey encompassing different parts of the energy storage, or “new energy” value chain with Japanese companies.

From manufacturing of lithium-ion batteries with Panasonic, to flow batteries with Sumitomo Electric, to creating the technology around aggregating fleets of distributed storage and advising stakeholders including utilities on strategies for adopting these “new energy” assets, Behrangrad brings a holistic perspective to the conversation.

Behrangrad joined Pacifico in 2021 to set up its energy storage division. Recognised already as one of the company’s three pillars of its strategy, alongside solar PV and offshore wind, his department quickly from there executed the two projects simultaneously to begin bidding in the market this June.

Specific to Japan

What are some of the key takeaways that you’ve really taken from other markets and things that can work in Japan? What are some of the things that you really had to tailor more to be specific for the Japanese case?

What we can learn about from other markets is: first of all, ensuring you have a top line supply chain, you have a safety and quality point of view to projects from the very early stages, even though you might not have local regulation around it.

For example, in Japanese local firefighting regulation, there’s still not a need to have automated fire detection and extinguishing system in a system in a container itself. It’s definitely it’s going to be a little bit of cost reduction, but from our perspective, this is not a local business.

In terms of safety and quality, we should go window shopping around the world and try to select the best, even though you’re not forced doing it locally.

Second is making sure we have best in class solutions in place, going beyond the borders, because I strongly believe this is a very international business. In our case, we have batteries from China, PCS is from Korea, and the aggregation system is from Japan. How you want to marry all these things together, under Japanese regulation is something that is challenging.

Third is that always we should have a look on the pure business side in terms of being able to finance it and scale it.

We don’t hunt for subsidies. Even the first time that we got a subsidy was to demonstrate our capability, that we can do the things in a tight timeline. It’s very critical that from early stage of the business, you have a business strategy that doesn’t rely on any subsidy, otherwise, your growth and your margin is always decided by something that you have no control over. It makes it very difficult to make a financeable project or a scalable project.

[Another thing is] having an international pool of talent and expertise, because Japan still needs some catch up in that sense.

4-hour duration

Energy-Storage.news: The battery storage systems at Shiroishi in Hokkaido and Itoshima in Kyushu are assets with relatively long duration, compared to what’s typically seen in less mature markets for grid-connected battery storage. Presumably this sizing decision came after considerable modelling and simulation, but what’s behind that decision?

The result comes from considering a mix of parameters. Number one the modelling of how you forecast the revenue will be in the long run of the project.

The second parameter is the market regulation. For example, in Japan for to be able to bid into capacity markets, you actually need at least three hours.

Third, again, is the supply chain. We were talking about times [during the pandemic] when the supply chain situation wasn’t as comfortable as it is now. And when you have projects that will receive subsidies, you have external, non-project based limitations – timelines you need to commit to.

Do I want to change an off the shelf product? Considering that it might affect my delivery timeline? How much value does it add to the project?

It’s about making decision between all these parameters, and then coming to the conclusion to start with 4-hour duration. But I think the biggest part of it is simulations of the revenues we expect to earn, and a market framework that needed at least three hour for market for a battery to take part.

What’s in the revenue stack?

The business case for trading energy with battery storage has been enabled by changes in regulation to make standalone battery storage eligible. I don’t know if the mix of services you expect to be delivering and trading energy for might be a closely kept secret among yourselves, but can you tell us a little bit about what that sort of mix of applications will be?

Revenue stacking is critical. There’s no way you can survive, or let’s say make the project as profitable as your investors want, by just one specific application. So like, other markets that you cover at Energy-Storage.news, revenue stacking is there, for the whole life of the project.

Pacifico’s Shiroishi ESS project during construction in the Sapporo metropolitan region of Hokkaido, northern Japan.

[In my personal view] the important thing is that you should be able to have a realistic view of how the market will evolve. The revenue structure is not going to remain the same in the 20th year of the project as in the first. So it’s important to have a system from the beginning that can answer to those needs in the different stages of its life.

It has been the case in other countries and Japan will perhaps go through the same experience, is that in the beginning, ancillary service is going to make the trunk of your revenue. You have some capacity, and going forward new types of revenue streams will come. Then you will have the arbitrage portion of it. But when you evolve, and the project goes forward, the mixture and the usage of the battery would change.

It’s kind of a game of 3D Chess, or a 3D puzzle; how you make your cash flow model prophecy and how you believe the long term market will evolve. Actually in Japan it’s become 4D, because the regulation is also so dynamic, it’s not fixed. Some pieces of the rules were not there, so the detail is not clear. But the clock was ticking.

Routes to market

Can you tell us a bit about how the energy trading aspect works? The two new projects are essentially at opposite geographical ends of the country. Are there localised markets for power within the Japan Energy Exchange (JPEX), or is it cleared nationally?

The way JPEX is cleared, you have a system price, which is a mixture of all the prices [from around Japan] but the prices of each local area is decided based on the limitations of the area.

Everything in Japan again is just kind of right now transitioning to some more unified [system] but it’s kind of trying to act as if it’s a different system. Not all areas have the same price, but the energy price, the spot price is the same. So it’s just a matter of area. The same goes for the ancillary service prices, so each area has its own price dynamics.

That’s another challenge for anyone who wants to do business in Japan. Each area might not be that big, so it’s a fragmented market in that sense, and we have been present in Japan and been focused on it. So that’s why we try to taste different market areas, to test our theories.

Fundamental case for BESS in Japan

Japan has a long history of adopting and adapting to new technologies, and Japanese industry and academics played a key role in developing the rechargeable lithium-ion battery technology. Yet it’s fair to say development of a market in which battery storage can compete has taken some time. As a final question, what are your views on the fundamentals of the business case for energy storage in Japan?

I do believe it’s going to be an interesting market. I believe the dynamics and the big picture regarding energy storage in Japan has changed. I wouldn’t have joined Pacifico Energy with a focus on this topic if I didn’t.

It’s a matter of the bigger agenda of a nation or a country, and which direction it’s going in. Nobody should say, “Okay, we want energy storage [for the sake of it]”. Energy storage is just a tool.

The important thing is that the target they’re setting or the destination that they want to go to is definitely fixed, then along this journey, do they need this tool or not? If they need it it’s going to be an interesting thing.

It’s a matter of if the trajectory that they’ve decided for a nation for the energy system or energy policy or strategy.

In the long run, do they need this tool? And my answer is yes, in Japan, that is definitely needed. The need is not just economical.

In order to realise by 2050, the carbon neutrality that is promised, it’s a matter of pride of a nation, it’s not even a matter of energy, it’s a matter of delivering what this nation has promised. So in order to deliver it to be there, then you need some specific measures, you will need some flexibility in the grid What’s a good tool for flexibility? Energy storage. It’s going to be needed.

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

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The proposal, which is in draft form with public comment open for another week or so, would require a minimum ‘US-made’ proportion of an ESS’ of 40%, rising to 55% in 2027.

The proportion is based on the cost that an ESS’ different ‘products’ and ‘components’ account for (further explained in our coverage at the time), and this could mean a level of cost disclosure by system integrators that would prove problematic, as one developer recently told Energy-Storage.news.

Availability of US-made battery cells appears to be less of an issue considering the cost thresholds being proposed.

“Pretty aggressive” requirements for domestic content

“Some of the provisions around the timing for domestic content requirement were pretty aggressive, considering the level of price disclosures that would be needed from BESS (battery energy storage system) manufacturers,” said Jessica Shor, partner at developer Granite Source Power, which is selling a 2GW pipeline in ERCOT.

“There could be a challenge in getting manufacturers to disclose the different costs of the components that make up the equipment which historically they haven’t been willing to do. This seems to require them to do it.”

Energy-Storage.news asked system integrators to comment and has received two, highly contrasting responses from LS Energy Solutions and Mitsubishi Power Americas (MPA).

Mike McManus, VP business development & commercial operations at MPA’s energy storage division said: “As a system integrator, Mitsubishi Power remains enthusiastic about the opportunity to provide flexible energy storage solutions to our customers in an accelerated manner as a result of the IRA legislation. We continue to engage US-based suppliers in an effort to provide customers the ability to capture the 10% domestic content bonus adder in the future.”

McManus added it was also working through the more recent guidance on transferability and direct pay with trade bodies like American Clean Power.

However, LS’ director of strategy and market analytics Ravi Manghani gave a less favourable view of the implied cost disclosure requirements which he called ‘unattainable’, saying:

“The way the draft guidance is written, it almost changes the definition of “cost” from the cost to the taxpayer (i.e. developer/owner) to “cost” to the manufacturer – battery supplier, inverter supplier, container vendor, or system integrator, depending on how the products are procured, integrated by integrators like us or bespoke for integration onsite by an EPC (engineering, procurement and construction firm).”

“This approach has put the onus on system integrators to not only track the direct costs of each manufactured product (MP) and manufactured product components (MPCs) but also expose our cost structures and profit margins to our developer customers.”

“This is a double whammy for our business models and in our view, an unattainable approach.”

He added that the silver lining was the guidance is still in draft stage and may be changed to reduce the burden on system integrators. LS Energy Solutions recently commissioned two projects financed by the new ITC.

However, Mona Dajani, global head of renewables, energy & infrastructure at law firm Shearman and Sterling, was much more bullish on the domestic content adder, although conceded that the thresholds are high.

“I’m not seeing hesitation or skittishness on this. I’m seeing a lot of projects where they want to be abide by the domestic content requirement and want to be able to submit to the IRS for certification. It is a lot – 40% for solar and wind and storage and 20% for offshore wind. But I’m not seeing any kind of skittishness or chilling effect,” Dajani said.

“These are big companies, and they want to do everything they can to take advantage of these tax credit incentives.”

Dajani also said it was “not true” that the cost disclosures would reveal a system integrators profit margins.

“There’s a lot of things you have to disclose but you can structure it in a way where you are only disclosing exactly what you have to.”

Big BESS players are already trying to onshore manufacturing

System integrators have been seeking to strike US manufacturing deals in order to better serve their US customers in light of global logistics and supply chain challenges, but also with one eye on the domestic content adder.

Most recently, global BESS integrator Powin signed up with Jabil for the latter to produce its Stack750E utility-scale product, with an annual capacity of 2GWh starting later this year with plans to increase that to 4GWh.

The largest player Fluence plans to start completing its Cube units in Utah next year, although its announcement predates the domestic content guidance. The firm declined to comment for this article.

The requirements around the ESS product discussed in this piece come under the Manufactured Product portion of the domestic content requirements. The other portion, for Steel/Iron parts, was that the rebars in the concrete foundation of the ESS have to be 100% US-made.

The guidance was issued on 12 May and taxpayers were given 60 days to submit comments to the US Treasury and IRS on the proposed regulations, implying the deadline is Tuesday next week (11 July).

Solar PV is subject to the same minimum thresholds of US-made products for Manufactured Products, but significantly more for Steel/Iron parts. Read our sister site PV Tech’s coverage of the domestic content guidance in May here.

Energy-Storage.news will be publishing more on the topic in the coming weeks.

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It is currently mainly powered by coal with natural gas as a second support fuel for starting up the units, but it will be transitioned to a plant using solar panels and battery-based energy storage systems.

The Ministry’s announcement did not reveal the planned capacity of the respective renewable energy plants but said that a balance was being established to “…make the most of the connection point and establish the proportion of panels and batteries necessary for the transition.”

It added that a more specific project outline would be published for public comment in November this year.

Although the MW and MWh being considered haven’t been revealed, the number is likely to be relatively high to make use of the existing grid connection.

With grid presenting the challenge that it does, large existing connections make legacy power plants ideal sites for large renewable energy and energy storage projects, as Energy-Storage.news has written extensively.

Colombia has been relatively quiet for large energy storage project announcements, similar to most of Latin America for reasons which were recently discussed in an interview with pan-American energy storage solutions firm On.Energy, which is also active in the country, the region’s fourth-largest economy.

In 2021, Energy-Storage.news reported on Colombia’s first ever battery storage tender, from the Ministry, which was won by solar PV and battery storage firm Canadian Solar. The project at a mine was said to be coming online in June 2023, although no announcement has since been made.

Returning for the second edition in Santiago, Chile, the Energy Storage Summit Latin America will explore opportunities in countries such as Chile, Peru, Colombia, Argentina, Brazil and Mexico. Join Solar Media on October 17-18 to meet with investors, policy makers, developers, utilities, network operators, technology providers, EPCs, consultants, law firms and more to make sure you are a part of the rapidly evolving storage landscape in Latin America.

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The Pome BESS is a 100MW/400MWh project which has been under development since 2019. The BESS supply deal has been secured with an unnamed provider, and a ten-year tolling agreement has also been signed with an unknown buyer.

It is Eolus’ third BESS project in the US, after projects in Arizona and California which it has since sold ownership of but continues to develop under development services agreements (DSA).

In January last year, it sold the 120MW Cald project in Los Angeles to Aypa Power and then in October sold the 500MW PV, 250MW BESS Centennial Flats project in Arizona to an unnamed ‘large publicly traded global private equity investment firm’. Cald is expected to come online in 2024 while Centennial Flats, which it acquired at an early-stage back in 2018, is scheduled for 2026.

Centennial Flats has also progressed recently, last week obtaining site control and signing a grid connection agreement. The milestone means that Eolus has now been paid 40% of the total project acquisition consideration by the buyer of US$104-190 million.

Though Eolus didn’t reveal Pome’s offtaker, four-hour BESS projects in California generally supply energy to the state’s large investor-owned utilities PG&E, SDG&E and SCE, through long-term agreements under grid operator CAISO’s Resource Adequacy framework.

However, smaller, locally-focused community choice aggregators (CCAs) are also active, particularly in securing offtake from longer duration projects.

“There is a strong demand for energy storage in California to support the energy system and we are excited to realize this project. We see great interest for investing in renewable energy and energy storage”, says Hans-Christian Schulze, Country Manager of Eolus North America.

“Eolus has been active in the US since 2015 and we have a strong project pipeline, where the US projects make up one-quarter of Eolus’s total project portfolio. After the Inflation Reduction Act being signed the US market is really booming.”, added Per Witalisson, CEO of Eolus.

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