Doral Renewables LLC has successfully closed construction project financing for Mammoth North, the first phase of Doral’s broader Mammoth Solar project. Mammoth North is located on 4,500 acres in Starke County, Ind., in the northwestern region of PJM. The project will be a ground-mounted, single-axis photovoltaic system with 400 MW AC of solar power capacity. Doral is also developing the nearby Mammoth Central and Mammoth South projects which, together with Mammoth North, will bring 1.3 GW AC of capacity to market.

Deutsche Bank AG, New York Branch acted as sole bookrunner, sole structuring bank and mandated lead arranger for the $392 million financing for the project, which consisted of a $157 million construction-to-term loan facility, a $170 million tax equity bridge loan and a $65 million letter of credit facility. Bayerische Landesbank, New York Branch and National Bank of Canada acted as lead managers with debt and letter of credit facilities Banco de Sabadell S.A, Miami Branch; Comerica Bank, a Texas banking association; Intesa Sanpaolo S.p.A., New York Branch; and Metropolitan Life Insurance Company. The closing was completed simultaneously with Doral’s signing of a nearly $175 million tax equity commitment for the project from Bank of America N.A. Marathon Capital Markets LLC acted as exclusive financial advisor for Doral.

Mammoth North will generate energy and renewable energy certificate revenue via its long-term power purchase agreement with AEP Energy Partners Inc., a subsidiary of American Electric Power.

“We are proud to support Doral with this financing and to have partnered with their world-class development team and furthered DB’s commitment to Sustainable Financing,” states Jeremy Eisman, head of infrastructure, energy financing and structuring at Deutsche Bank.

“Doral is thrilled to have collaborated with Deutsche Bank to raise this important piece of capital which will enable us to bring Mammoth North to commercial operation as expected in 2023,” comments Evan Speece, CFO at Doral Renewables LLC. “We look forward to continuing to work with our financing partners to bring clean energy from the other stages of Mammoth, and the rest of our growing pipeline, to customers throughout the United States.”

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A render of Darlington Point, one of three battery storage sites making up the 300MWh project. Image: Edify Energy.

Australian renewable energy developer Edify Energy has secured project financing for three battery energy storage system (BESS) projects in New South Wales, Australia, totalling 150MW/300MWh.

A long-term syndicated loan facility is being provided by banks Commonwealth Bank of Australia (CBA), Westpac and DNB for Edify Energy and technology supplier Tesla to complete the projects in stages during the first half of 2023.

The three projects are partitions of one site co-located with the 333MWp Darlington Point Solar Farm, also developed by Edify and operational since late 2020. They are the:

60MW/120MWh Riverina Energy Storage System 165MW/130MWh Riverina Energy Storage System 225MW/50MWh Darlington Point Energy Storage System

The financial close comes a month after Federation Asset Management took a majority stake in the three projects and three months after Edify chose automative giant Tesla’s utility-scale product Megapack as the underlying battery technology of the sites. They will all connect to the nearby Darlington Point substation.

Edify has retained a minority interest and remains project developer. The company has already secured offtake agreements for all three projects: oil and gas giant Shell for Riverina Energy Storage System 1 and utility EnergyAustralia for Riverina Energy Storage System 2 and Darlington Point Energy Storage System.

The BESS projects have grid forming inverters that will allow them to support the local grid by providing synchronous inertia, something relatively new for batteries, as Edify CEO John Cole explained:

“In this instance, we’re using the combination of the dispatchable properties of batteries with a new vintage of grid forming inverter control systems to create a generator that can provide power system support services, which have traditionally been provided by thermal synchronous generators.”

The press release doesn’t give any financial details about the loan or project. But a State Significant Development Modification Assessment in late 2021 said that Edify was seeking to modify development consent to increase the system specs from 50MW/100MWh to 200MW/400MWh, which would “increase the project’s capital investment value by A$174.6 million” ($120 million). The project’s planned size has changed several times in the last few years before its final power and capacity were settled on.

The BESS will play into Australia’s National Electricity Market (NEM) and the Modification Assessment gives an idea of the role it will play: “Further, increasing the capacity of the BESS would provide an additional and substantial investment towards improving the reliability of the network at Darlington Point (substation), provide storage and firming capacity to the NEM, and provide ancillary services which contribute to the stability and functionality of the electrical grid.”

New South Wales is quickly becoming a hotbed of huge BESS projects as it closes various coal plants. The regional government recently announced financial support for a 1,400MWh BESS project currently being tendered while renewable energy company Maoneng recently proposed a 1,600MWh BESS unit co-located with a solar farm.

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Two of Recurrent Energy’s PV projects in Southern California. Image: Recurrent Energy.

Lucas Moller, head of energy storage development at Recurrent Energy, discusses the rise of solar-plus-storage in the US: where the market has come from and where it’s heading.

Around 60% of new solar PV projects planned for deployment in US utility service areas over the next two years are hybrid resources paired with storage.

That’s equivalent to about 6GW and growing all the time. Although a clear majority of this new capacity will be clustered in the leading regional markets for solar, like California or Arizona, it’s increasingly becoming a national phenomenon.

For context, Wood Mackenzie Power & Renewables said in recent research that a total 3GW of utility-scale energy storage came online during 2021 in the US, so it’s clear batteries paired with solar will be a significant complement to standalone battery storage in terms of new additions.

Particularly in areas like the desert Southwest in Southern California, Arizona or Nevada, it makes more sense to add battery storage to large-scale solar than to not, Lucas Moller, head of energy storage development at Recurrent Energy says.

Moller was one of the contributors to our recent feature article for PV Tech Power, where representatives of technology providers and developers active in the US solar-plus-storage market ranging from community and distributed scale to grid-scale shared their experiences and insights.

To read that article, which also includes conversations with folks from IHI TerraSun, Stem Inc and Nexamp, subscribe to the quarterly journal here (or read an extract on the site here).

Today, we discuss the solar-plus-storage market with Lucas Moller in more detail. Recurrent Energy’s parent company Canadian Solar said in its quarterly financial results release a couple of weeks ago that it now has a pipeline of nearly 27GWh of energy storage project opportunities, of which 15.5GWh are in North America.

That’s in addition to 1,400MWh already in construction in the region, and a significant portion will be hybridised with solar.

All of Recurrent’s solar-plus-storage projects executed to date are in California, including Slate, which paired 300MW of PV with 140.25MW/561MWh of battery storage and went online earlier this year.

However, he explains, that’s perhaps more to do with California’s solar market reaching maturity earlier than other places, rather than California being some unique outlier. Recurrent Energy looks at all solar projects as potentially also energy storage projects, because that’s how it’s projects in California began their development cycle as early as 2014.

“We look at all solar projects as solar-plus-storage projects, and as it pertains to California, and I’d say, the Desert Southwest [in general], there’s no such thing as a solar-only project anymore,” he says.

“There is pretty much a fundamental need to add storage to every project to make it economically viable.”

“It is directly associated with the degree of solar penetration. The reference, of course, for everyone is the Duck Curve, which is fundamentally driving value in energy shifting. That is creating necessity for storage.

“But further than that, it’s saying, any marginal solar that comes online needs to effectively ameliorate the very low or sometimes negative value of midday energy and so we don’t want to create a new plant that is primarily going to be stranded out there injecting low value power in the middle of the day if it’s a standalone PV asset.”

“For the buyers in these markets, whether it’s a regulated market like Arizona or an open market in California, the value of that midday energy is so low in every marginal megawatt of renewable power that you buy new plants, you want it to be associated with the ability to shift and not be exposed to that low value in the middle of the day.”

What California does have are contracts for resource adequacy (RA), which has led to a lot of four-hour duration battery storage coming online. How does resource adequacy fit into the business model for battery storage?

Four hours of battery storage, gets you resource adequacy value in the California market. It serves as a similar concept in some of the regulated markets in the western interconnect as well.

What this means is that load serving entities, whether that’s investor-owned utilities (IOUs), community choice aggregators (CCAs) etc, they need to provide a certain amount of resource adequacy to cover their load plus a planning reserve margin of 15% – 17.5%.

What that means is a lot of storage projects today — it is primarily true of standalone but it is also very true of retrofits at solar plants — were in fact primarily driven by the value of [resilience] paired to the energy shifting value alone.

Slate, which Recurrent Energy developed and sold to Goldman Sachs Renewable Power. Image: Goldman Sachs Renewable Power.

Slate includes 561MWh of BESS. Image: Goldman Sachs Renewable Power.

It’s quite a step up to see solar PV being considered regulatorily as a capacity resource isn’t it?

For sure. And I will say that in a place where there is high midday demand, solar does provide capacity value. The problem is when that solar generation source exceeds that midday demand, or nearly exceeds that midday demand, that’s when the effective value of that capacity resource drops.

So instead of being a static capacity resource, it turns into a dynamic capacity resource to adapt to that shifting peak, when you add storage.

It’s interesting that RA can be covered by four-hour duration battery storage, which was long considered the upper limit for lithium-ion battery energy storage system (BESS) technology in terms of cost-effectiveness. However, we’ve started to see six and even eight-hour lithium battery projects get underway in California through clean energy supply contracts. How much is the selected duration of projects a function of RA?

The four-hour standard is really driven by the resource adequacy qualification.

While there is value for sure in shifting four hours between zero-priced energy in the middle of the day to US$60 to US$80-priced energy in the evening ramp, that market value doesn’t necessarily underwrite a four-hour duration [BESS].

When you look into the operational math in California, it may be something like two or three-hour duration is ‘economically optimal’ from a markets perspective. It’s again the RA requirement and the fact that you get paid for this service separately out of market that’s driving four hours.

If you go to other markets outside of California, some are using a similar standard, some are looking at a little bit more complex math through effective load carrying capability support, kind of a more dynamic view of how much duration equals capacity value.

But in short, depending on the cost benefit of what that capacity value is in a given market versus how much it’s going to cost you in terms of building out an extra hour of lithium-ion battery capacity, it’s an ongoing question and debate, and certainly with battery prices being volatile — but increasing in the recent short term — it becomes a question of: ‘what is economic even with a capacity price?’

In California, we’re going to build a lot of lithium-ion batteries, probably even out to eight hours of duration and that’s partly because, from a policy perspective, California has decided against adding new gas-fired capacity and is rather going to rely upon that new resource adequacy coming primarily from energy storage resources.

In terms of longer duration projects how much interest is Recurrent Energy taking in long-duration energy storage (LDES) technologies, which might be alternatives to lithium-ion at eight hours or more discharge time?

We’ve definitely looked at long duration, both from a fundamental technology perspective of what is out there and how it competes or squares up against lithium-ion.

What are the pros and cons? And every technology has its nuances.

What Recurrent has seen – and is validated by some recent procurements – is that lithium-ion is more economical up to eight hours. I think once you get beyond eight hours, it may be a little bit more of a question, particularly given current market prices [for lithium].

But those flow batteries and other technologies out there often have high costs for their initial scale. Many of them do promise, or expect to have, cost declines over some time, but their cost declines cannot start until they reach scale.

So there’s a little bit of a Catch 22 until they start really developing or the market starts out for multiple long-duration projects, particularly very long-duration, in excess of eight hours, where these things are going to start to make more economic sense.

To be specific, I am referring in part to a couple of recent long-duration energy storage RFP awards made to some other developers in California. There’s also been an award for a vanadium redox flow battery (VRFB) resource, but in general, the CCAs that are awarding these projects have seen that lithium-ion is cheaper.

One last point on this is that these are not necessarily economic decisions to purchase these PPAs for long-duration systems. They’re in part driven by California policy mandates for a certain amount of long-duration energy storage to be added.

California is a major focal point for solar-plus-storage today, but among Recurrent’s other developments is Hummingbird, a project in Kentucky which is anticipated to include 200MWac solar PV and up to 200MW/800MWh of battery storage. Its targeted online date is by the end of 2024, but Kentucky’s perhaps not somewhere people immediately think of as a booming state for solar-plus-storage. How different are the economics of solar-plus-storage there as opposed to California?

To be clear, there’s a lot of competition in Kentucky. It’s not to say there are a lot of projects built, but there are a lot of people trying to build projects in Kentucky.

There are a couple of reasons for that. On the solar side, it’s actually got pretty decent sun and it’s in PJM Interconnection, or parts of it are, where there is an extreme demand for renewable generation. Not to get too into the weeds in PJM mechanics, but it’s common knowledge these days that that market has really slowed their interconnection advancement process.

So the supply is far short of the demand for new renewables. Not just solar, but also wind generation. That’s markets-driven, whether that’s renewable portfolio standards (RPS) and/or corporate procurement goals.

As it pertains to solar-plus-storage, we see, again, planning for the future, an opportunity in these markets. As that demand does get met, we’ll see a much higher penetration of solar resources in PJM over time, again, creating that kind of fundamental value for storage on the market side and then as a capacity resource as well.

PJM has been making headway as to how storage can be valued for as a capacity resource, especially around that four-hour mark. Those two things are good leading indicators for the opportunity, apart from just the pure demand for new solar PPAs.

The US’ biggest vanadium flow battery installation to date. Recurrent continues to track developments in the long-duration tech space, Moller says. Image: Sumitomo / SDGE.

Where else in the US do you foresee Recurrent and others in the market being busy in the next few years?

Solar demand is high in PJM, it continues to be high in ERCOT (in Texas), there’s a lot of projects that are waiting to come online in ERCOT and there’s various supply chain and interconnection timelines to work through for the entire industry right now.

But there’s a lot of pent-up demand for new PV in these markets. Again, a lot of it is driven by corporate procurements that are kind of mission driven.

PJM and ERCOT are the big ones in the US, apart from California, which is almost a given, but we are seeing increasing demand pretty much everywhere in the US.

Despite some supply chain constraints, leading to slightly higher prices, and even in less greatly sunny areas, there is a demand for reliable, price consistent power.

As we see fossil retirements happening throughout the country. There’s a natural replacement with these reliable low-cost renewables. As those come to fruition and get built out, we see storage, basically following suit, right behind, to help provide that capacity value and provide that energy shifting value.

Finally, there is so much solar-plus-storage in the US, particularly as it is eligible for investment tax credit (ITC) support, whereas standalone energy storage is not. Is there ever a sense – perhaps if that ITC eligibility changes – that standalone energy storage and solar-plus-storage might be in competition with one another for market share?

I don’t really see either cannibalising one or the other.

In particular though, standalone energy storage has a difference in locational value as well. You’re going to put standalone storage batteries in places you can’t put hundreds of acres of PV panels, so it has a different market value and different value to the grid for reliability specific to certain areas.

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US President Joe Biden visiting a National Renewable Energy Lab (NREL) solar facility. Image: NREL.

Actions taken this month by the US government to support the country’s solar industry are unlikely to come at the expense of support for energy storage, Energy-Storage.news has heard.

On 6 June, President Joe Biden announced a two-year waiver on tariffs for solar modules imported from Southeast Asia, even as an investigation is ongoing by the Department of Commerce into whether facilities in the region are being used by manufacturers to circumvent duties on imports from China.

As reported by our colleagues at PV Tech, the decision has been widely welcomed by the downstream US solar industry, which accounts for the vast majority of jobs and economic activity in the sector, versus the upstream, which includes just a handful of domestic makers.

Abigail Ross Hopper, executive director of the Solar Energy Industries Association (SEIA) said the move would restore the “paralysed” market.

At the same time, Biden moved to support domestic manufacturing through invocation of the Defense Production Act (DPA), Cold War-era legislation which allows the government to place manufacturing and production on a footing similar to that required for a war effort or national emergency.

Although earlier in the year Biden had already said the DPA would be used to support battery manufacturing value chains, in this most recent announcement, five “critical” clean energy technologies were mentioned by name: solar module parts, building insulation, heat pumps, equipment for making clean fuels such as electrolysers and fuel cells and finally power grid infrastructure such as transformers.

Energy storage was left out of the announcement, but that doesn’t mean the government won’t use the DPA to support batteries and other technologies after all, Jason Burwen of the American Clean Power Association (ACP) said.

“Although battery energy storage was not included in the DPA Title III declaration by the White House, it’s important to recognise that the bipartisan infrastructure legislation Congress passed last year appropriated US$3 billion for battery manufacturing investments and US$3 billion for battery minerals processing and recycling,” Burwen, ACP’s VP for energy storage, said.

“That’s among the largest direct investments the US government has ever made in a clean energy supply chain, and it represent funds actually available today.”

Burwen noted that the DPA funding on the other hand still needs to be appropriated via Congressional approval, for both the most recent declaration and the DPA declaration around batteries made in March.

‘Energy storage still remains part of the larger picture’

Morten Lund, a partner at law firm Stoel Rives assisting energy project developers, said that solving the solar tariff issue was simply the more pressing priority for the president.

The so-called anti-dumping and countervailing duties (AD/CVD) imposed on the industry had led research firm BloombergNEF to slash its US solar deployment forecast for 2022 from 30.5GW to 22.7GW and came about as the result of complaints by a group of mostly-anonymous US-based manufacturers led by California-headquartered outfit Auxin.

“I don’t believe that storage was intentionally excluded so much as the White House was targeting a specific issue—the potential Auxin tariffs.”

Biden’s imposition of a two-year tariff freeze being paired with support for domestic makers via the DPA, addresses concerns that the continued import of solar – and other clean energy – goods would harm local suppliers, Lund said.

The lawyer believes energy storage remains “part of the larger plan,” but the key priority at this stage is getting solar deployment back up on its feet.

Jason Burwen noted that the US Department of Energy already has its first solicitation out for battery manufacturing grants, which ACP thinks should accelerate development of a domestic battery supply chain.

“Additionally, other agencies like DOE’s Loan Programs Office have authority to invest in the battery supply chain, and we are eager to see how it may use its authority.”

For ACP and its members, it is important to take a “multi-faceted and comprehensive approach to accelerating US storage,” and as with one of its predecessor organisations, the Energy Storage Association, the trade group continues to advocate for the investment tax credit (ITC) for standalone energy storage deployment as well as tax credits for domestic manufacturers, Burwen said.

Previous forecasting by Wood Mackenzie Power & Renewables has found the ITC could result in an estimated uplift of more than 20% to annual energy storage deployments in the US.

Back in April, as the DPA Title III declaration to support critical battery minerals and materials processing and production was made, several industry participants and experts told this site the move was a positive one.

However, there still remains a huge mountain to climb in terms of making the US less dependent on imported materials and processing capability it had gradually outsourced abroad, Dr Francis Wang, CEO of advanced battery tech company Nanograf said.

Danny Lu, VP of energy storage manufacturer Powin Energy pointed out the lengthy timelines for getting upstream production to market and said it will be important to offer specific support directed at stationary storage batteries, as well as for electric vehicles (EVs).

Caspar Rawles, chief data officer at lithium battery market information provider Benchmark Mineral Intelligence said that permitting new upstream resources is usually the biggest hindrance to getting them online quickly. Rawles noted the President’s order expressly stated the government would not intervene to expedite permitting.

The problem-solving “really needs to accelerate things because the problem is here now — it’s not five years down the road, it’s here today and it’s going to continue to grow from here,” Rawles said.

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Tricera Energy exhibiting at Intersolar / ees Europe in Munich last month. Image: Cameron Murray / Solar Media.

German battery energy storage system (BESS) project developer Tricera Energy has been able to build its business thanks to ‘second use’ battery modules from the country’s automotive sector, its COO told Energy-Storage.news.

The Dresden-headquartered company has a 120MWh pipeline of projects for delivery by the end of 2023 but had to come up with an alternative to sourcing batteries the traditional way, as COO Lars Fallant explained:

“We don’t order batteries from China because we are too small for them to be interested in working with us, or the price is too high, which is why we use second use batteries from the automotive sector.”

The company repackages battery modules into BESS units starting from 100kWh in size, which it sources from the country’s EV industry, one of the largest in the world. ‘Second use’ means unused batteries, as distinct to ‘second life,’ which means repurposing of used vehicle batteries.

Fallant explained how it is able to procure unused battery modules in the scale required to do its BESS projects:

“Sometimes a production line will cease and there will be leftover battery modules we can use. Or, the automotive player makes more batteries than they need because of warranty agreements which were not exercised, and they don’t want to use ‘old’ batteries in their new lines. Right now there is also a chip shortage which has meant a relative overproduction of batteries in some cases,” he said.

“In all these cases, they sell to us for a good price and these are our core supply of batteries. We also have a small supply of batteries from our shareholder, which is a forklift company that builds its own battery modules. A third supply source which is small for now, but which we want to grow, is second life or recycled batteries from the automotive sector. Again, we’ve started here with our shareholder.”

The main challenges with second use battery modules – module disassembly into the constituent cells would be too costly – are two-fold according to Fallant. First, you need to design your own battery management system (BMS). Tricera’s shareholder had an existing basic one that Tricera was able to build on.

The other challenge is the variability in the size and charge type of the modules being used, meaning the mechanical structure of the rack needs to be built flexibly enough to accommodate this.

Energy-Storage.news has reported on several moves from EV industry players to repurpose vehicle batteries this year.

In April, Mercedes-Benz tied up with Swedish startup BatteryLoop to provide both new and second life batteries for the latter’s energy storage system (ESS) solutions. A month earlier, Jaguar Land Rover launched an off-grid ESS unit using only battery cells from prototype and engineering test vehicles of its first electric SUV, Jaguar I-PACE.

In March, energy group Enel started operating a 4MW backup power storage system at a plant in a Spain-held North African territory using repurposed Nissan electric vehicle (EV) batteries. Audi supplied used batteries from its e-tron EV to a 4.5MWh BESS project which launched in Herdecke, Germany, in January.

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The Southeast’s largest floating solar plant will be producing power soon at the U.S. Army’s Fort Bragg in North Carolina after a major utility energy service contract with Duke Energy and its prime contractor Ameresco. The 1.1 MW solar facility is part of a $36 million contract that focused on energy resilience and security at Fort Bragg, including infrastructure modernization, lighting and water upgrades, heating, ventilation and air-conditioning, and boiler system improvements.

“Duke Energy’s work with Fort Bragg will lead to better energy efficiency and cost savings at the base,” says Brian Savoy, Duke Energy’s chief strategy and commercial officer. “We’re excited to help put Fort Bragg at the forefront of renewable energy innovation through this unique floating solar facility.”

The floating solar system was built on the Big Muddy Lake located at Camp Mackall. Fort Bragg will own and operate the solar system.

“We are grateful for our relationship with Duke Energy and Ameresco,” comments Col. Scott Pence, garrison commander for Fort Bragg. “With this system, the largest floating solar array in the Southeast, we will be able to provide energy resiliency to Fort Bragg operations through sustainable resources. With this partnership, Fort Bragg not only has renewable electricity, but energy security that will be critical with continuing the installation’s mission during a power outage.”

The floating solar installation is being paired with a 2 MW battery energy storage system. The system will supply power to Fort Bragg from the local grid and provide power during electric service outages.

“The opportunity to implement this innovative use of clean energy technology for a military base as notable as Fort Bragg was one that our Federal Solutions team was thrilled to lead on,” states Nicole Bulgarino, Ameresco’s executive vice president and general manager of Federal Solutions. “The completed floating solar system – still an underutilized technology in the U.S. – will assure the Army’s mission with clean energy. We look forward to continuing our relationship with Duke Energy and Fort Bragg, working to identify additional state-of-the-art opportunities to reduce the installation’s energy consumption and strengthen its resilience.” “This project fulfills the commitment made in our Army Climate Strategy to increase resilience while delivering clean energy and reducing greenhouse gas emissions,” adds the Honorable Rachel Jacobson, assistant secretary of the Army for installations, energy and environment. “When we collaborate with local utilities and industry to promote energy resilience while powering the local grid, it is a winning solution across the board.”

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Andrew Flanagan

RWE AG’s executive board has appointed Andrew Flanagan as COO of RWE Renewables Americas as of July 1, 2022. The role of COO has been held by Silvia Ortín as a dual responsibility alongside her CEO duties; the role of CFO has been assumed by Ingmar Ritzenhofen.

“I’m delighted Andrew Flanagan, having a wealth of renewable energy knowledge across all facets of the business, will join our experienced team in North America as COO,” says Markus Krebber, CEO of RWE AG. “Together with Silvia Ortín and Ingmar Ritzenhofen on the board of RWE Renewables Americas, he will forge ahead with the expansion of our onshore wind and solar portfolio in North America, one of our strategic key focus markets.”

In his role as COO, Flanagan will be responsible for continuing growing the business and overseeing operations to keep the 35+ operating projects in North America on track. RWE constructs, owns and operates wind, solar and energy storage projects in the U.S., having installed more than 5,000 MW of generation capacity to date.

“We’re happy to welcome Andrew to the RWE Renewables Americas Board,” states Silvia Ortín, CEO at RWE Renewables Americas. “With his extensive renewables background in management, development, financing and construction, Andrew’s experience matches very well to our existing team. We look forward to adding his leadership experience to help us expand our operating portfolio in North America.”

Flanagan comes to RWE from his position as senior vice president and chief development officer at Leeward Renewable Energy, where he led project development and power functions, managing a team with a project pipeline of more than 19 GW.

“I am thrilled to be joining RWE at this exciting period of the company’s further expansion of renewable energies and I look forward to being a part of RWE’s ambitious plans for a clean, secure and affordable energy portfolio,” states Flanagan.

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Another Renesola completed project, the 2.6 MW Helen solar project in Minnesota (Image: Renesola Power)

Solar project developer ReneSola Ltd. (ReneSola Power) has picked up 20-year index renewable energy credit (REC) contracts for two solar projects in two states. The New York State Energy Research and Development Authority has selected ReneSola Power’s 22 MW Roosevelt Solar project in Massena, N.Y. to be one of 22 projects as part of the state’s largest land-based renewable energy projects. ReneSola Power was awarded a 20-year index REC contract as part of the state’s renewable program in an effort to reach New York’s goals to exceed 70% renewables by 2030 and zero emissions by 2040 as required by Climate Leadership and Community Protection Act.

In addition, the Illinois Commerce Commission has awarded a 20-year index REC contract to ReneSola Power’s 20 MW utility-scale solar project in Wilmington, Ill. as part of the state commitment to double investment in renewable energy towards its goal of 40% renewable energy by 2030 and 50% by 2040.

“We are very excited and honored that our two utility-scale solar projects in New York and Illinois were awarded REC contracts,” says Yumin Liu, ReneSola Power’s CEO. “The solar industry continues to benefit from the accelerating green energy transition to fight climate change. Our projects are in line with our environmental, social and governance practices, that is, not only will it contribute to state-level renewable energy targets, but it will also make an impact to the local communities by creating jobs.”

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A map of Boralex’s five winning solar projects, one of which – Fort Covington – is co-located with storage. Image: Boralex.

New York has awarded 22 solar PV projects totalling 2.4GW of power, including six co-located sites with a combined 159MW of battery energy storage systems (BESS).

The awards represent the state’s largest land-based procurement of renewable energy to-date, first covered by Energy-Storage.news‘ sister site PV Tech. The 22 projects will require US$2.7 billion in investment and some or all should be online by 2025.

Winning co-located projects from developers EDF Renewables (three) and Boralex (one) account for 85% of the 159MW of awarded BESS capacity, with ReneSola Power and Northland Power also adding storage onto their winning solar projects.

EDF Renewables, part of the global French state-owned energy group, will deliver three sites with 20MW of BESS each: Columbia Solar Energy Center in Herkimer County, Ridge View Solar Energy Center in Niagara County and Rich Road Solar Energy Center in St. Lawrence County.

Columbia and Ridge View are also the largest winning solar projects by power, with 350MWac each, and Rich Road’s 250MWac brings EDF’s total contribution to 950MW, 40% of the 2,408MW awarded.

Boralex is pairing its 250MW Fort Covington Solar Farm with a 77MW/308MWh (four hours) BESS, in Suffolk County, while its four other winning projects are standalone solar: all five total 540MW of solar power.

EDF has not revealed the duration/MWh of its three BESS projects. Though this varies greatly in the state of New York, it may be trending towards hour hours with Boralex’s winning tender and a Summit Ridge project announced last week both opting for it. And in April, the New York Power Authority (NYPA) began a process of adapting fossil fuel sites to be replaced with four-hour BESS units.

Rounding off the winning co-located projects, Northland Power is adding 20MW of storage to its 100MW Alfred Oaks Solar project in Allegany county, while ReneSola Power is pairing its 19.99MW Roosevelt Solar project in St. Larwence with 2MW of storage.

“Today’s investments will put us on a path to making New York a greener place to live while also creating new jobs and spurring economic development,” governor Kathy Hochul said. “These projects will allow us to not just meet but exceed our goal of obtaining 70 percent of our electricity from renewable resources (by 2030) and will further cement New York as a national leader in the fight against climate change.”

The contracts for the 22 projects include an index REC (renewable energy certificate) structure which will help cushion electricity consumers in the state against spikes in energy prices. The weighted-average all-in development cost of the projects amounts to $63.08 per megawatt-hour.

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Solar-grade Siemens chunk polysilicon (Image: REC Silicon)

Ferroglobe PLC, a producer of silicon metal, silicon-based alloys and manganese-based specialty alloys, has signed a memorandum of understanding (MOU) with REC Silicon. Under the MOU, Ferroglobe commits to leverage its asset platform in the United States to supply high-purity silicon metal to REC Silicon aimed at jointly establishing a low-carbon and fully traceable U.S.-based solar supply chain.

Hanwha Group’s recent investment into REC Silicon, in conjunction with Hanwha Group’s subsidiary Qcells, has expanded REC Silicon’s relationship with Ferroglobe and plan for the immediate development of an end-to-end U.S. solar supply chain from silicon metal to polysilicon to fully assembled solar modules. The project would span from Washington State to Georgia, West Virginia and beyond.

Passage of Senator Jon Ossoff’s Solar Energy Manufacturing for America Act as part of a broad clean energy incentive package would make such plans immediately possible.

Ferroglobe will be a partner in ensuring steady supply of fully traceable metallurgical grade silicon metal produced in the U.S. from locally sourced raw materials and utilizing its domestic workforce. Ferroglobe is leveraging its technical and operational expertise across sites in West Virginia, Alabama and Ohio to support this effort.

As a producer of high-purity electronics and solar grade polysilicon with assets in Moses Lake, Wash. and Butte, Mont., REC Silicon is positioned to help lead the U.S.’s clean energy transition. The recent Hanwha investment will enable a re-start of the currently idle Moses Lake plant in 2023 and make available high volumes of low-carbon, solar-grade polysilicon.

“The solar industry is vital to the future of the global energy transformation,” says Dr. Marco Levi, Ferroglobe’s CEO. “I am thankful for Senator Ossoff’s leadership on this important initiative, which will re-shore solar capacity in the U.S., and increase jobs to help the economy. Furthermore, we are excited to collaborate with REC Silicon on this important initiative. We have had a longstanding relationship with REC, and this MOU aligns both company’s respective expertise and competencies towards a common goal which is critical to the United States.”

The MOU commits the companies to work together to increase U.S. production and employment at each of the companies’ affected facilities. “It is imperative that the solar manufacturing industry grows and diversifies,” comments James A. May II, CEO of REC Silicon. “REC is committed to driving large-scale investments in the United States, and we believe that the passage of SEMA in particular would result in the creation of tens of thousands of high-paying manufacturing jobs across the sector, accelerating the U.S. transition to clean energy.”

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