A report on state government- and utility-driven initiatives affecting electric vehicles (including hybrids) shows the majority of such efforts continue to focus on rebates and incentives for consumers and commercial fleet operators to acquire them. However, regulations and actions to modify electricity rates relating to EVs and develop charging infrastructure are also moving forward.

The Q2 2024 edition of “50 States of Electric Vehicles” published by the NC Clean Energy Technology Center (NCCETC) at North Carolina State University said a total of 561 EV actions were taken during the timeline of the report. In 2024, as of early August, 29 states have enacted legislation related to transportation electrification. Massachusetts, New York, California, Illinois, New Jersey, Minnesota, Michigan and Hawaii were the most active in this regard, the report said.While the report shows that governments continue to invest heavily in creating markets and incentives for growing EV numbers, certain trends are showing the effects of these vehicles in the real world. For example, more states are imposing additional registration fees for electric vehicle owners, with most U.S. states now having such fees in effect. Also, a growing number of states are opting to adopt per-kWh fees for electric vehicle charging.

The publicly available executive summary of the $500 report did not identify a cause for these actions; however, it’s no secret that states imposes such charges in order to recoup gas taxes lost from non-hybrid EVs bypassing gas pumps.

The report also shows the growing footprint of EVs on the nation’s electricity grids. Utilities are developing charging programs to manage the EV charging load. The report cites NV Energy’s proposed charging programs as part of its latest transportation electrification plan as well as Xcel Energy’s request for a new active managed charging program in New Mexico. Actions of other utilities proposing to offer EV owners incentives to divert charging to during off-peak hours.

More importantly, a growing number of utilities are filing expansive transportation electrification plans on a routine schedule, the report said, with several states now requiring this.

“As the adoption of electric vehicles continues to grow, so too does the EV focused utility offerings, with an increased focus on active managed charging programs,” Emily Apadula, policy analyst at NCCETC, said in a statement. “These programs allow the utility to directly control a customer’s charging load in order to remotely optimize charging times and reduce stress on the grid.”

Houston-based Sage Geosystems has started construction on a 3 MW geo-pressurized geothermal energy storage system in Christine, Texas. The announcement follows a land-use agreement signed with the San Miguel Electric Cooperative Inc. (SMECI) enabling the location of the facility near an existing coal-fueled power plant. Sage will serve as merchant, buying and selling electricity to the Electric Reliability Council of Texas (ERCOT) grid.

The storage system, dubbed EarthStore, is based on Sage’s dry rock geothermal technology, which consists of a drilled well into which water is pumped and kept at ambient heat and pressure in subsurface rock formations. When electricity is needed, the naturally heated and pressurized water is released to run a Pelton-type hydroelectric turbine generator. The storage facility is expected to have six to 10 hours of capacity.

The SMECI project will be the company’s first commercial storage facility. Sage CEO Cindy Taff said the coal plant will not have any bearing on storage operations, except as a source of water, and that the idea is to buy electricity from ERCOT to run pumps when demand and prices are low. When ERCOT experiences high demand Sage will run its turbine and sell the power.

“We’ll be drilling the well in September and building the facility,” Taff told pv magazine USA. “We’ll have everything done by the end of December this year.”

Ideally, Taff says, the EarthStore system would serve as a long duration energy storage companion to solar and wind generation, where surplus energy is used to run the pumps. The amount of storage depends on the number of wells available: more may be drilled to increase capacity on site. The pumped water may be stored indefinitely and when released delivers a round-trip efficiency of 70-75% with a water loss of less than 2%, she said.

The EarthStore system is one of family of geothermal storage and baseload energy systems Sage is developing. A more ambitious geothermal generation technology drills a series of wells to depths of 9,000 to 20,000 feel, where ambient temperatures range from 218- to 485-degrees Fahrenheit. In such systems, pressurized steam is liberated to run Rankin-cycle turbines to generate electricity. A more advanced version will heat pressurized, supercritical CO2 to drive a specialized turbine with greater efficiency.

Sage has contracts with the Department of Defense to develop geothermal baseload generators and microgrids for its facilities. It is conducting feasibility studies at the Army’s Ft. Bliss and Air Force’s Ellington Field bases, both in Texas. A prototype geothermal plant is under construction at the latter site. In addition, Sage has a test site of its own in Starr County.

According to Taff, the primary advantage of Sage’s approach to geothermal storage and generation is that it uses existing drilling techniques from the oil and gas industry to produce renewable energy from rock formations that exist essentially everywhere. All of the 16 GW of existent geothermal energy is produced from hydrothermal locations linked to volcanic activity – relatively rare occurrences.

“If you look at the continental U.S., we can put storage even in the East, where the geothermal potential is a little bit more challenge,” Taff said. “We can do it in the West, where you have good geothermal potential. So, we can pair with wind or solar just about anywhere. We are actually looking at pairing with solar to provide off-grid, 24/7 power for data centers and other customers who need tons of power.”

SEG Solar officially opened its new photovoltaic module manufacturing facility in Houston on August 8 with a gala event featuring a ribbon-cutting ceremony and live country music. The automated factory line has an initial capacity of 2 GW of n-type panels per year with plans to expand to 5 GW by 2030.

“You see this facility?” said Jun Zhuge, SEG’s founder and chief operating officer, addressing an audience of mostly customers, partners and local officials gathered for the opening. “We have invested $60 million right here in Houston. We’re not just talk.”

The new factory and headquarters complex features 145,000 square feet of manufacturing and warehouse space and 16,000 square feet of office space. The fully automated production line – SEG claims it’s the longest PV line in the world – takes in glass and cells and runs through production stages over conveyor belts all the way through framing and packaging. There are numerous stations for various inspection and quality assurance processes. The hands-off line requires 12 technicians to attend the machinery, although more were on hand for training purposes.

“We don’t just want to make money,” Zhuge said. “We want to build solar manufacturing in this country. We want to bring all of the supply chain to this country.”

Conceived by co-founders Zhuge and Jim Wood, who serves as chief executive officer, SEG Solar was launched in California in 2016. Through 2021 the company established cell and module factories in Southeast Asia and China. The photovoltaic cells that feed the Houston operation are sourced from Indonesia, but the company says it is committed to producing cells in the U.S.

A veteran of investment banking and solar installation businesses, Wood eventually went to work for a large Chinese solar manufacturer. He teamed up with Zhuge and other partners with industry experience, and they decided there was a real opportunity to establish a successful American module producer under the right circumstances.

“We looked at a lot of the lessons that we’ve learned from myself and other folks here working at other manufacturers and we said, we’re going to lean heavily into automation,” Wood told pv magazine USA, adding that the production machines are the largest of their types available. “Those stringers are 1.3 times faster than any other stringers in the world. So because we’re fully automated, because the capacity of those lines are larger, because the machines run faster, we’re able to be as competitive here as we would be in Southeast Asia.”

According to Wood, the company looked at other regions to establish its U.S. manufacturing base but decided that Houston offered a number of key advantages for SEG Solar’s strategic development plans. He cited Houston as having one of the best ports in the country, a large and educated labor force with many skills and a very friendly business atmosphere. Moreover, Texas is already the second largest solar market in the U.S. with 42 GW installed as of Q2 2024, according to the Solar Energy Industries Association, and is poised to become number one next year.

Wood stresses that SEG Solar’s purpose is not to satisfy domestic content requirements or circumvent tariffs. It is a 100% U.S.-owned company, with the principals assuming financial as well as managerial responsibility for its operations.

“SEG is financed internally,” he said. “We don’t have private equity. There are no external owners. We haven’t taken any outside debt. We’re a true American company where we’ve taken our profits, recycled them and grown this business organically.”

Urban rooftops offer inviting platforms for commercial and industrial (C&I) and community solar projects. At the same time, even so-called flat roofs on warehouses and big box stores have features and irregularities that require precise and time-consuming site investigation before design of a solar array can begin.

Many solar developers are turning to drone operators to not only investigate proposed solar sites more quickly but to also and use multiple sensors to obtain a fuller understanding of a given site’s characteristics and suitability for hosting solar.

Brooklyn-based Drone Drafting says it has completed over 4,000 project surveys across the U.S. representing mapping of over 2.5 GW of proposed solar capacity. Emmett Witmer, Drone Drafting’s director of operations, told pv magazine USA that a drone team can accomplish more in two hours than a survey team on foot can in a day and less expensively.

“These rooftops – even the flat ones, funny enough – are not all symmetrical,” he said. “There’s often a lot of differences. Sections have been built bits and pieces, maybe at different times. Moreover, surfaces can have all these weird undulations that naked eye surveys can miss.”

The drone quadcopters carry optical payloads that can survey sites using multiple sensors across the spectrum. Optical cameras, thermal imagers and laser-based lidar systems provide a complete representation of a proposed solar location, showing subtle surface variations, elevation of obstacles, signs of subsurface moisture and the presence of lines and hanging wires.

“They’re really granular data,” Witmer said of the images produced. “Software tools enable us to turn those into highly accurate orthomosaic maps. Our engineers use them to produce fully drafted 2-D and 3-D AutoCAD files.”

While C&I-scale rooftops are the Drone Drafting’s primary business, Witmer said it performs drone surveys for prospective carport solar projects and ground-mount arrays. These sorts of project sites have their own sets of complications, from shadows cast by surrounding structures or trees to terrain contours. These can all be readily revealed with multiple sensors with a drone’s eye view.

Drone Drafting founders got their start in aerial cinematography for documentary films and marketing videos. Shooting marketing footage for a solar project planted the idea of using drones for solar site surveys as part of the project development process. The company has its own done pilots and works with operators throughout the country, and in Europe and Asia as well, to expand the reach of its services.

“Who we use depends on location and the complexity of the site,” Witmer said. “The majority of the time we just have local pilots that we subcontract. If it’s a super technical or otherwise hard job we’ll use an in-house pilot so there’s easier communications and we can make adjustments on the fly.”

In addition to site mapping as an aid to project design and engineering, Witmer said the company is able to provide services throughout a project’s life cycle. Thermal cameras can detect hotspots in solar arrays and lidar can help evaluate growing vegetation and construction that might affect the site over time.

A panel discussion on community solar at the RE+ Mid-Atlantic solar and energy storage conference in Philadelphia made the point that developers many have to embrace opportunities close to the intended customer, even in difficult terrain.

While state regulators design programs to encourage solar development on rooftops and brownfields of urban New Jersey, developers often prefer to build projects on undeveloped greenfield sites. Leslie Elder, vice president of policy and public affairs at Summit Ridge Energy, a Virginia-based solar developer, said that companies don’t always agree with state priorities, but that’s where the project opportunities are.

New Jersey’s Solar Act of 2012 includes provisions for streamlining and permitting and providing financial incentives for developers to construct utility-scale solar projects “located on a brownfield, on an area of historic fill or on a properly closed sanitary landfill facility.” The idea was to turn urban lots, commercial flat roofs and fallow industrial areas into productive sites for clean energy.

Greenfield sites, such as unused agricultural land or other undeveloped properties, generally are easier to deploy solar on and have required less specialized site preparation procedures than brownfields. However, the New Jersey BPU restricts grid-connected projects of 5 MW or larger on many categories of greenfield-type land. Waivers may be applied for but are often rejected.

“There is a real opposition from the state [New Jersey] for a wide variety of reasons to greenfield development, mostly because of population size and past sparring,” Elder said, adding that New Jersey’s community solar policy focus is on urban development and low-income beneficiaries.

Elder contrasted New Jersey’s approach to community solar with Maryland, which defined “buckets” for different types of projects. For example, there was a greenfield bucket; a brownfield bucket, landfills and “cleanfields” (landfills with no toxicity); and a low- and moderate-income bucket. These sorts of definitions for community solar opportunities enabled developers to bid on projects based on their experience, specialization and preferences.

State siting requirements are just one aspect of the community solar puzzle. More intractable, perhaps, are the labyrinthine subscription and billing policies needed to attract customers and have them see real economic benefits. And, as always, developers committing to building community solar projects need to see the financial rewards for doing so.

Eric Wallace, an attorney at the Virginia-based firm of GreeneHurlocker, PLC, with a focus on energy law and energy regulation, said successful community solar program design hangs on the statutes that set them up on a state-by-state basis.

“There are a lot of different policy tools out there, but finding the right solutions for each state is a challenge,” Wallace said. “In each of these markets there are interconnection proceedings and discussions happening. That’s definitely a key component of community solar in the Mid-Atlantic.”

Justin Felt, director of policy analysis and development at Exelon, which is parent to six utilities, said it would be beneficial to incorporate the utility perspective at the association level rather than making that the opposition view.

“Getting sort of that collaboration I think would be better,” Felt said, echoing comments made by SEIA CEO Abigail Ross Hopper earlier that morning. “Let’s also be honest, politics – purple state versus blue state – is going to be a big impact on this. If you’re in a red state, maybe it’s a little bit different. So, we have to follow our jurisdictions in a lot of ways. You have to appreciate that the broader political and policy landscape is going to be a prime driver as well.”

If state policies are important for developing grid storage capacity, as was discussed in an earlier RE+ panel, they are likely even more so for community solar, which is arguably more complicated a proposition.

The role of battery storage on the grid was a major focus of the RE+ Mid-Atlantic conference in Philadelphia last week. In addition to numerous storage vendors and consultants on the show floor, a panel of experts assembled to discuss storage strategies for the PJM interconnection area, covering the Mid-Atlantic region.

There was broad agreement that successful storage implementation requires clear and purposeful policies at the state level. At the same time, the levels of storage capacity envisioned as an aspect of the clean energy transition may exceed the experience of policymakers, utilities and developers.

“I think it’s fair to say that in PJM there’s been less storage deployment than in other areas that we’ve seen, such as California, New England and New York,” said panel moderator, Nitzan Goldberger, director of policy and business development at New Leaf Energy, a Massachusetts-based renewable energy developer. “We’re going to try to understand not only why that’s happened – what are the obstacles and challenges to getting storage in the ground in the PJM footprint? – but also what are we doing about it?”

From a utility standpoint, the problem seems to be ambitious targets with no clear roadmap showing how to achieve them. Erik Henlon, senior manager of distribution planning at Baltimore Gas and Electric, one of the utilities under the Exelon umbrella that serves the PJM region, said the conversations with stakeholders is still at the early stages.

“From a distribution planning perspective, we look at how we’re enabling all these new technologies to help meet the Maryland goals of 3,000 MW of storage by 2033,” Henlon said. “I think that we starting on the journey, right? And we’re putting the right foundations in place because for us to be able to utilize this much storage on the system takes a certain level of planning and it takes a certain level of collaboration with different stakeholders.”

If there is a tendency to view storage technology as a solution not only for achieving clean energy targets but also for rectifying what some see as community inequities in legacy generation, this can sometimes obscure the practical steps needed to achieve these results. Tyler Wakefield, associate executive director of the Energy Policy Design Institute, a Baltimore-based non-profit focusing on turning clean energy goals into projects, said specific policies are responsible for a state storage markets, or the absence of them.

In the case of Maryland, Wakefild said the recent passage of the Drive Act mandating utilities support bi-directional charging of EVs and time-of-use tariffs enables customers with behind-the-meter storage to realize energy savings on their bills, promoting EVs and residential storage.

“Unless those time-of-use tariffs are in place, those savings opportunities aren’t really there,” he said. “And then we get into what revenue opportunities are available for private storage assets to take advantage of on the distribution system. And right now, there’s really not much there, and that’s why a lot of the conversation at Maryland is, how do we create a mechanism by which resources can get paid directly for the services they can provide on the grid?”

Specific policies make the difference between storage as a mandate and possible burden on the utility and opportunities for all stakeholders to come out ahead with rate and demand stability. According to Wakefield, other states with healthy storage markets have focused on reducing the distribution system peak. That can save a lot of money for utilities and a lot of money for ratepayers. “But if there’s not a clear mechanism by which storage assets can discharge against that peak, get paid for doing that work, there’s not a revenue generating opportunity that’s meaningful enough to deploy,” he said.

Greg Geller, CEO of Massachusetts-based Stack Energy Consulting, agreed that states that have seen a lot of storage deployed have been willing to allow owners to monetize those services storage enables.

“For instance, in the Northeast, there’s a number of programs, whether it’s Massachusetts, New York, Connecticut, Rhode Island, that recognize storage can do things to reduce the bulk level capacity requirement,” he said. “Or it can reduce distribution level costs, or it can help with emissions, right? So, each of those states has some kind of mechanism in place that allows storage to say, ‘Hey, if you dispatch during these periods and you provide the service and everyone benefits from it, we’re going to pay for it.’ That really doesn’t exist in the PJM region.”

Geller pointed out that targets are nice but if you just have a wholesale market, developers are going to find investors very reluctant to finance storage projects. He said states have to step up and make sure storage is compensated for the different services it can provide.

BG&E’s Henlon said utilities in the PJM region are essentially at the ground floor when it comes to implementing storage, despite ambitious targets like Maryland. However, success in other states and regions could be applicable to the PJM service area.

“Each state is in a different place, right?” he said. “A lot of us look at what’s happening out West or in the Northeast. It takes some time for different states to catch up. So, I think that’s a key thing when we’re thinking about the opportunities to grow storage in our area.”

The $7 billion Solar for All program administered by the U.S. Environmental Protection Agency (EPA) as part of the Inflation Reduction Act (IRA) seeks to support solar, storage and energy efficiency projects that benefit low-income and disadvantages communities. A panel of stakeholders at last week’s RE+ Mid-Atlantic conference in Philadelphia discussed how the program that aims to expand access to solar faces pending deadlines, possible shifting political winds and complications arising from its compliance requirements.

Solar for All is an aspect of the EPA’s $27 billion Greenhouse Gas Reduction Fund made possible by changes in the Clean Air Act authorized under the IRA. In this sense, the allotment is a creation of the Biden Administration and the RE+ panelists were cognizant of a potential change in administration coming next year. Although as signed legislation, the IRA has the force of law, individual provisions and allotments, particularly those originating from rule changes in federal agencies, that could be affected by new priorities.

Abigail Ross Hopper, president and CEO of the Solar Energy Industries Association (SEIA), a key sponsor of the conference, noted in her introductory remarks that she was fresh from the Republican convention in Milwaukee and found a substantial cadre of support for renewable energy there. At the same time, she indicated prudence dictates that the solar industry should “regime proof” the money Solar for All makes available.

In her role as moderator of the Solar for All panel discussion, Hopper identified the importance of the looming September 30 deadline for the 60 state, tribal and non-profit entities selected by the EPA to contract with developers for specific projects.

“You might pick up that September 30th is six weeks before Election Day,” Hopper said, stressing the deadline was critically important for the durability of the program. “Making sure those funds are obligated will ensure that they continue regardless of what happens at Election Day.”

Maryrose Myrtetus, executive director of Philadelphia Green Capital Corp., which partners with the Pennsylvania Energy Development Authority for the $156 million grant for the state, said the key goal now was to get the money under contract and obligated to make sure that the funding is set aside and secured for the work.

“We’re all working with the EPA right now to get contracts in place by that deadline,” Myrtetus said, adding means vetting installers to make sure they are technically competent, have the right background, are properly insured and provide for consumer protections.

“Some standards that we have include ensuring that consumers can save money starting in year one when they go solar, limiting the escalator on a lease price or [point of total assumption] price, insurance requirements for third party owners and on,” she said.

This means Philadelphia Green Capital will be running an aggressive request for proposal process in the fall to meet the deadline.

Easier said than done. Solar for All’s mandate to serve low- and moderate-income communities as well as neighborhoods disadvantaged by legacy fossil-fuel generation due to pollution and other factors has placed an emphasis on community and distributed solar and storage projects. Such projects are often more complicated than single-family and commercial installations in terms of local permitting, siting, interconnection and managing off-takers. It is not surprising that the panel featured Solar for All grantees with community and multi-family dwelling solar expertise.

Meghan Jennings, distributed energy resources specialist at Rappahannock Electric Cooperative, said her non-profit utility is partnering with Groundswell to provide the sort of experience it needs to not just to develop effective community solar projects but to build in grid resiliency, outage services and other functions to support ratepayers.

Chris Walker, vice president of policy and programs for GRID Alternatives, a multi-state non-profit administering nearly $250 million in program funds, says his organizations’ history developing solar for low-income homeowners in partnership with Habitat for Humanity and other groups will serve as foundational experience for moving forward under Solar for All.

“We thought the affordable housing sector was an important partnership type to pursue, given that there’s also an intersecting housing crisis together with a climate crisis and affordability crisis in the need to really give folks some relief in terms of how much their incomes are paying for their utility costs,” Walker said.

Intensions are good and experience matters, however there are certain unavoidable aspects to using funds under Solar for All. Perhaps more important than acquiring experience in the low-income and community solar markets is finding ways to navigate the labyrinthine requirements for using federal money.

Kristal Virgil, senior vice president at Groundswell Inc., selected as a multi-state non-profit to administer $156 million in EPA grants in the Southeast, said the federal source of the funding triggers a number of compliance issues, including the Davis-Bacon Act that mandates how contractors are paid and compensated, and the Build America/Buy America Act (BABA) that requires U.S.-source products (with a few exceptions, such as electronics) and construction materials used for infrastructure projects funded by the IRA.

“We’re currently in the process of working on a position description now for general counsel to be added to Groundswell’s team because there are several compliance responsibilities that we’re going to need to take on,” Virgil said. “There’s a lot of complexity that we’re currently navigating through and looking to partner with experts. We’re going to need legal and accounting and a robust compliance manager.”

This complexity underscores the reality that Solar for All is not just a $7 billion resource ready to be tapped for solar. It can only be accessed according to very specific procedures. The fact is, there are extremely few contractors and suppliers that are Davis-Bacon and BABA-compliant. This threatens to create monopolies or simply immovable blocks to Solar for All projects.

All in all, the compliance issues facing those entities selected to administer funds under Solar for All appear more pressing than the technical problems attending solar development for low-income households. And the clock is ticking.

Salt Lake City-based renewable energy developer rPlus Energies says it has secured over $1 billion in financing for the 800 MW Green River Energy Center (GREC) in Emery County, Utah, one of the largest solar-plus-storage projects in the country.

Originally conceived as a 400 MW solar facility with 200 MW of on-site storage, the GREC has expanded its storage component due to the requirements of the project’s primary off taker, electric power company PacifiCorp. The solar facility will now incorporate 400 MW of battery storage, which is expected to supply 1,600 MWh of electricity.

Increasingly, storage is seen as an important component in utility-scale solar development projects. With GREC, rPlus assumes the role of owner operator of one of its projects. The company has a power purchase agreement with PacifiCorp.

“The Green River Energy Center marks rPlus Energies’ debut as an independent power producer,” said company president and CEO Luigi Resta.

rPlus says the construction debt financing for GREC is being supplied by Crédit Agricole Corporate and Investment Bank, KeyBanc Capital Markets, MUFG Bank, Ltd., Truist Securities Inc., and Wells Fargo Securities, LLC, with MUFG acting as administrative agent.

Engineering, procurement and construction services will be provided by Sundt Renewables. GREC will join a number of other rPlus projects in the state, including the 200 MW Appaloosa I solar project, the 80 MW Three Peaks Solar facility, 80 MW Graphite Solar project and 80 MW Utah Red Hills Renewable Park.

rPlus says GREC is expected to supply approximately 500 construction jobs, with a significant percentage to be local hires.

rPlus Energies, a subsidiary of the Gardner Group since 1976, develops utility-scale power plants using renewable resources. The company has projects across 15 market areas in the U.S. in active development including solar, wind, pumped storage hydro, and solar-plus-battery.

Lithium-ion battery storage is beginning to play a more important role in backing up the utility grid. However, concerns about fire safety in these systems are rising along with installations, and handling a battery fire is not necessarily routine for first responders. Manufacturers are working with industry, regulatory bodies and the community to ensure safe operations and effective emergency responses.

One way to investigate fire safety in lithium-ion batteries is to set them on fire. Last May, Sungrow, a China-headquartered inverter and battery storage provider, which has its U.S. headquarters in Cosa Mesa, Calif., conducted a fire test to demonstrate the thermal management capabilities of its PowerTitan grid storage system. The exercise, conducted at a third-party facility in China and livestreamed to subject matter experts, utility engineers, fire protection consultants and other stakeholders, simulated a “thermal runaway” event in a battery energy storage scenario with multiple units.

According to Mandy Zhang, Sungrow’s battery storage product manager for overseas regions, this large-scale combustion test realistically replicated the layout of a power station’s energy storage system. A thermal runaway event was instigated in a single module causing a fire.

During the test, explosion relief panels atop the unit in which the fire was set automatically vented the fire upward to prevent it from spreading to adjacent battery units. The test event unfolded without intervention by personnel or fire suppression systems until the fire burned itself out.

“Before conducting this large-scale fire test, Sungrow had already performed multiple system-level fire tests and research,” Zhang told pv magazine USA. “The research on energy storage safety will continue to progress with the development of energy storage technology.”

In this sense, the large-scale test was more of a demonstration of thermal management capabilities intended to assure the above-mentioned stakeholders. Based on feedback, Zhang said, the test has addressed some customers’ concerns about the safety of liquid-cooled energy storage.

Lithium-ion batteries are widely used in many fields, making any fire incident highly publicized. Zhang said this leads to a perception of increased fire risk.

“We believe the industry’s focus on fire risk is mainly due to a lack of understanding of fire in energy storage systems,” she said. “Statistical data shows that the actual fire risk is relatively low. Reports from organizations like the National Fire Protection Association and the U.S. Consumer Product Safety Commission support this.”

Zhang believes that current fire safety certifications and standards in certain regions are lagging behind the rapidly increasing installed base of lithium-ion battery storage. She said that battery manufacturers must work with relevant standards bodies to keep them up to date on battery storage and management systems

“Applying existing building fire safety standards to energy storage system products is not very meaningful for product fire safety and can even become an obstacle,” said Zhang. “We hope that more innovative safety technologies can be applied to energy storage systems, particularly in developing countries and regions, as well as by local firefighters. In many cases, these first responders are not familiar with energy storage system fires and may apply techniques that are not well-informed.”

According to the U.S. Energy information Administration, battery storage capacity in the country is on track to double in 2024, with developers planning to bring the total to over 30 GW by the end of the year. The vast majority of these new batteries are based on lithium-ion technology, which dominates the industry. However, lithium-ion batteries are in some ways a victim of their own success as perceptions of fire safety issues are growing along with installations.

John Zahurancik, president, Americas, of battery-maker Fluence Energy, said failures are going to happen with any equipment that has a significant installed base. The trick is to understand how and why failures happen and to make sure everybody affected knows what they are dealing with when they do.

“Some electrical transformers will fail just because you have millions and millions of units that are being shipped,” Zahurancik told pv magazine USA. “Not everything will be done perfectly, whether it’s manufacturing or installation or some random event like a lightning strike.”

Electric transformers have a large installed base, and while failures sometimes cause explosions or fires, it doesn’t mean the technology is inherently unsafe; it means there are a lot of them out there. As a result, fire and utility crews have become experts at handling and replacing transformers when they fail.

Zahurancik said the energy storage industry is working with standards organizations, first responders and professional associations to understand the characteristics of lithium-ion grid batteries in order to make them safer and more reliable.

“There has to be intelligence on the part of suppliers to make sure battery grid storage systems stay safe and effective throughout their lifespan,” he said. “There’s definitely design elements to managing safety and thermal events.”

Major suppliers such as Fluence have battery management systems incorporated into their grid storage projects. However, this is just a start, Zahurancik said, adding that to ensure operational safety:

• Companies need to have emergency response plans incorporated into every into every battery project;
• The projects themselves should be structured as multiple smaller battery storage units in order to reduce the spread of fires and make them easier to contain; and
• They should provide training to first responders at local fire departments where projects are to be deployed.

According to Zahurancik, expertise needs to flow readily between supplies, contractors, operators and first responders to prevent thermal events from making the news and warping public perceptions of lithium-ion battery safety. The company has representatives in fire safety standard bodies, such as the [National Fire Protection Association] NFPA 855 technical committee on energy storage installation.

“When things don’t go well, we have to talk about that in the spirit of, hey, everybody shouldn’t have to learn this lesson on their own,” he said. “We’re part of the American Clean Power Association and, one of its big pushes is to collect some of this information and propagate the best safety approach.”

Sometimes the best way to prevent fires is to start them and study the results. In May, Sungrow conducted a burn test of a 10 MWh installation to demonstrate the ability of its PowerTitan battery energy storage system to manage a thermal event without having it spread to other cabinets or require invention by emergency crews. The test was livestreamed to stakeholders and fire consultants.

“Too often, renewable energy skeptics raise fire safety concerns, even though batteries are overwhelmingly safe,” said the manager of energy storage engineering at Sungrow Americas, in a statement after the test. “These criticisms slow the adoption of such technologies.”

A recent report by Tennessee-based carbon solutions platform Clearloop noted that private companies have contracted for 71 GW of new renewable energy capacity in the U.S. since 2014, which is enough electricity to power nearly 15 million homes. However, the distribution of solar and wind projects tends to cluster regionally, and not only because of the availability of wind and solar resources. State and utility renewable energy policies play a huge role in where new projects are sited.

Clearloop, which is a subsidiary of solar power producer Silicon Ranch, partnered with non-profit emissions data analysis firm WattTime to study how renewable energy projects – and solar in particular – could be sited to produce better environmental and even social outcomes. The resulting white paper, Curing Carbon Blindness, reinforces the important role of private sector action in growing renewable energy in the U.S. while at the same time saying such action can be better focused to achieve decarbonization goals.

By incorporating the principle of “emmissionality,” the report suggests, companies looking to purchase renewable energy credits (RECs) or offset to their carbon footprints should seek to contract with solar and wind projects in regions with the highest percentage of fossil fuel generation.

Under the current structure, all RECs are essentially created equal, meaning an offtaker in one part of the country can buy RECs from a project anywhere else. There are differences in regional markets, such as ERCOT, but this is generally how it works. Laura Zapata, co-founder and CEO of Clearloop and one of the authors of the carbon blindness report, said not all MWh of clean energy are created equal in terms of their environmental impact.

“We still get over 60% of our electricity in this country from fossil fuels,” Zapata told pv magazine USA. “And so, our goal is how do we build more solar projects in the most carbon intense communities, which also happen to be often the most underserved and disadvantaged communities.”

Unlike most countries, the U.S. does not have a single national energy grid. It is more like a continent with many regional grids of widely varying emissions characteristics. Some regions, such as California, have grids with high percentages of renewables, while others, such as in the southern Appalachians, have fossil-fuel-heavy generation.

According to the Clearloop report, turning on a light switch in eastern Kentucky will result in 54% more carbon emissions than turning on a corresponding light in Los Angeles. This same data show that a new solar plant located in eastern Kentucky will reduce emissions by 62% more than the same plant would in Los Angeles.

By combining historical irradiance data with WattTime’s marginal emissions data, Clearloop says it is able to model not only how much electricity a solar project is expected to supply the grid, but also the marginal carbon intensity of the power generation sources it is displacing in that region at specific times.

Zapata argues that the marginal difference in emissions that results when solar generation displaces fossil fuel generation should be a key factor in citing projects. Using WattTime’s emissions analysis methodology, Clearloop had identified the regions of the U.S. where new solar, the report’s main focus, would have the greatest decarbonization impact by reducing a like amount of fossil fuel generation sources.

The analysis also extends to voluntary carbon offset markets that rely on private carbon credit registries, such as Verra or Gold Standard. This enables a company to use the methodology for contracting with solar projects to offset its carbon footprint from activities other than electricity consumption, such as air travel.

“Our clients are not interested in the electricity,” Zapata said. “What they want is credit for the environmental impact of those electrons flowing into the grid. So, whether they count them as RECs or offsets, we’re sort of agnostic.”

Researchers at Lawrence Berkeley National Laboratory have developed a new methodology for estimating the value of climate and air quality benefits from wind and solar generation. A report describing the results of an analysis of data from 2019 to 2022 using the methodology concludes that wind and solar generation provided $249 billion dollars of climate and air quality health benefits over that period.

Renewable energy advocates argue that the levelized cost of electricity (LCOE) does not tell the whole story when comparing the economics of wind and solar generation with fossil-fuel sources. Emissions from natural gas- and coal-fired plants in the form of carbon dioxide (CO2), sulfur dioxide (SO2), and nitrogen oxides (NOx) affect the climate and air quality in ways that should be accounted for in the evaluation of renewable energy’s benefits.

The researchers draw on publicly available electricity generation data and break the continental U.S. into ten regions in which wind or solar supplied at least 3% of electricity demand. An 11th region centered on Tennessee was excluded because the thresholds weren’t met. The methodology measures daily generation from appropriate sources (solar, wind, gas and coal) by region and a yearly average of emissions by region. The reason for averaging emissions is that there is generally a significant delay in the availability of daily emissions data.

According to the report, in 2022 the generation-weighted average across all regions in shows that 1.0 MWh of wind generation offsets 0.89 MWh of fossil generation (0.29 MWh of coal generation and 0.60 MWh of gas generation); and that 1.0 MWh of solar generation offsets 0.76 MWh of fossil generation (0.14 MWh of coal generation and 0.62 MWh of gas generation).

The offsets are not one-to-one because of transmission loss from solar and wind sources, which tend to be located further from consumers than fossil-fuel sources and curtailment issues. Also because some generation is absorbed by battery storage, which was not factored into the analysis method. Furthermore, other sources such as nuclear and hydroelectric typically are not displaced by solar and wind generation and so were not factored in, the researchers said.

In order to determine the dollar value of climate and air-quality benefits resulting from lowered emissions, the researchers turned to published reports in scientific journals: a 2022 article in Nature for determining the social cost of carbon; and a 2019 article in Environmental Research Letters that evaluated the social costs of pollutants such as SO2 and NOx.

With the generation offsets and social costs of emissions in hand, the Berkeley Lab researchers were able to calculate the health benefits of renewable generation. The researchers found the 435.6 TWh of wind generation produced in the U.S. during 2022 prevented 228,798 kilotons (KT) of CO2, 116 KT of SO2 and 129 KT of NOx emissions, resulting in total health benefits worth $62.4 billion. Solar provided 116.1 TWh of generation, preventing 45,729 KT of CO2, 15 KT of SO2 and 28 KT of NOx emissions, yielding $11.6 billion in health benefits.

According to the researchers, their new methodology shows the benefits of renewable generation are much higher than have been previously estimated and could help make a strong case for increasing wind and solar penetration in the U.S. Moreover, the analysis tools could be applied anywhere sufficient data are available. “The relatively simple data needed for our approach increases the possibility that it could be adapted to other regions around the world,” the researchers said.

Robert Gibbons, Strategic Development Manager at Trina Solar US, entered the world of photovoltaics about three years ago, coming from the oil and gas industry. Fossil fuel projects were becoming less common and a new universe seemed to be opening for renewable energy with the pending Inflation Reduction Act (IRA) Despite its rather misleading name, the IRA is a massive federal support mechanism for renewable energy.

“One of the biggest benefits of the Inflation Reduction Act has been raising the visibility of tax policy on prospective solar projects,” Gibbons told pv magazine USA. “When’s the last time you’ve had a 10 -year time frame where you feel pretty good that these tax credits are going to be there, right?”

The federal solar tax credit of the 2010s, which along with inexpensive China-source PV panels, energized the solar industry in the U.S. With that tax credit set to expire, Congress increased it from 26% to 30% and extended it through 2032.

Gibbons added that the IRA has come along at a time when just putting projects together has become that much more difficult because of a combination of rising interest rates and what he calls the structural constraints of longer interconnection queues. He said his 30 years in financing, mainly of infrastructure projects, a lot of which were for the oil and gas industry, has given him a good understanding of what is needed to move projects forward, especially during difficult economic times.

While critics point to the money being set aside under the IRA as being itself inflationary, Gibbons is more sanguine on the law’s positive effects, which he said helps enable effective and profitable solar projects to get the green light. He pointed out that an important element of the IRA is its provision for the transferability of tax credits.

In the proposal stage, solar projects may seem like a house of cards. A successful project needs a developer to oversee the design, engineering, land acquisition, legal issues and financing. Financers, in particular, want to know there are going to be guaranteed off-takers for the electricity generated. In addition, there has to be a dependable supply chain to equipment manufacturers and possibly resellers. Today, the availability of tax credits can make the difference in whether a proposed solar project is viable or not.

“We do not advise clients on how to manage a project to get the various tax credit adders,” Gibbons said, emphasizing that this was not Trina’s role. “However, with the transferability of tax credits under the IRA, we and our partners can buy these and provide clients with confidence in a project’s economics.”

Recent guidance from the Internal Revenue Service outlines the domestic content credit a clean energy project may receive for incorporating equipment manufactured in the United States. Because of the surge in interest in U.S. manufactured solar modules, Trina Solar US is building a 5 GW capacity solar module manufacturing facility in Wilmer, Texas. Gibbons said Trina moved quickly on the opportunity to develop the facility, which will produce PV components as well as assemble modules from components produced in China.

“We had a lot of interest on behalf of our clients in using modules from that facility,” Gibbons said. “Not only because of domestic content benefits, but wanting to also support the development of solar manufacturing in the U.S.”

As much as Gibbons appreciates the tangible benefits of the IRA and IRS rules to the U.S. solar industry, he is also cognizant that politics cannot be counted on forever to support PV and other renewable energy projects. The recent laws and rules have been key, he asserts, but at some point the industry will have to stand on its own. Yet at the same time, it may be too big to fail.

“The IRA starts to phase out and it’s gone by 2032,” Gibbons said. “At that point, we should have a large, sustainable solar generation and manufacturing industry, right? And if it needs more help after that, what politician is going to want to get in front of that and put an end to it?”

A recent report by the International Energy Agency said lithium-ion batteries remain the key storage technology for the energy and transportation sectors. While mining for lithium is keeping pace with increasing demand, lithium refining and production of battery packs is concentrated in China, which causes some concerns in the West over supply chains and market dominance.

Sodium is emerging as a viable material for solid state batteries for many of the same energy storage applications that now favor lithium-ion systems.

Bor Jang, chief science officer and board chairman of Solidion Technology, an Ohio-based developer of solid battery technologies, told pv magazine USA that as many countries become dependent on batteries for important sectors of their economies, they will be prompted to search for alternative formulations to those based on lithium, which is relatively rare.

“Sodium, by contrast, is much more abundant in the Earth’s crust and oceans and is evenly distributed around the world,” he said.

In addition to its abundance, which leads to lower costs and easier supply chains, sodium-ion formulations have advantages in faster recharge rates and improved fire safety over lithium-ion ones, Jang said. The tradeoff is that sodium-ion batteries have less energy density (watts per kilogram), which translates into shorter ranges for electric vehicles and less overall storage capacity for grid operators for the same footprint.

However, Jang said, sodium-ion batteries are perfectly suited to EV uses where a 150-mile range would not be a burden, such as for local utility fleets or commuter driving, and where their faster recharge cycles would be appreciated, as would the projected lower price. Similarly, grid-storage facilities where footprint is not an issue would benefit from recharge rates and fire safety characteristics.

On the manufacturability side, Jang said sodium-ion batteries could be produced in factories that currently make lithium-ion batteries with only minor changes to the equipment.

“Solium-ion batteries have the potential to be useful across a wide range of applications, not just those dominated by lithium-ion technology” Jang said. “They can be used in place of lead-acid batteries, for example. Such demand will bring down prices.”

A materials scientist by education, Jang said he turned his attention to solid-state battery research and development about 20 years ago as the needs of the proposed energy transition from fossil fuels to non-emitting sources clearly would require a dramatic increase in energy storage capacity, particularly with renewable generators such as solar and wind. He founded a number of companies focused on the supply of materials for solid state battery electrolytes, anodes and cathodes.

Earlier this year, he saw the merger of his Honeycomb Battery Co. with Nubia Brand International Corp. which gave Solidion status as a publicly traded company. It joins a number of competitors hoping to commercialize sodium-ion batteries.

Jang said Solidion is working with the U.S. Department of Energy through one of the national laboratories, not announced, and the University of Texas, Austin, to improve the performance of sodium-ion battery technology. In particular, the focus is on improving the energy density electrolyte and replacing expensive cobalt and nickel in battery components.

California-based Quino Energy says its new pilot production line is ready to produce its proprietary chemistry for flow batteries. The company will produce electrolytes for existing commercial designs of flow batteries, which use tanks of charged and uncharged solutions to discharge electricity across a membrane. The technology is seen as a possible alternative to in-demand lithium-ion batteries for grid storage applications.

Eugene Beh, co-founder and CEO of Quino Energy, said his company’s electrolyte chemistry based on quinone, an organic compound, is intended to replace vanadium, a metal valued for flow batteries due to its ability to hold a charge but that is expensive and can be difficult to source.

“Our first step as a company is to focus on our organic battery formulation to replace vanadium in existing battery designs,” Beh told pv magazine USA. “Ultimately our goal is to produce the complete battery package to utility and commercial customers.”

The new manufacturing line is expected to be able to produce 100 KWh of reactant solution per day and joins two smaller test lines for lab work. The production facilities exist at Quino’s partner, Electrosynthasis near Buffalo, N.Y. Quino is using its flow batteries as part of a 12 kW solar photovoltaic microgrid at its San Leandro, Calif., headquarters.

In September 2021 Quino received $4.58 million from a U.S. Department of Energy (DOE) program long-duration energy storage research funding program. According to the funding announcement, this funding was awarded “to strengthen the U.S. domestic flow battery manufacturing ecosystem by developing and executing a scalable, cost‐effective, and continuous process for producing aqueous organic flow battery reactants”. DOE noted that this  investment is part of DOE’s Energy Storage Grand Challenge, critical to achieving the Long Duration Storage Shot goal of reducing the cost of grid-scale energy storage by 90% within the decade.

Quino is also receiving venture capital funding and investment from Israel-based Doral Energy Tech Ventures and from London-based Energy Revolution Ventures.

A chemist by background and a native of Singapore, Beh invented and commercialized a redox flow desalination technology as a researcher at Xerox PARC. He started Quino Energy in 2021 with co-founder Meisam Bahari, who serves as the company’s chief technology officer.

Beh’s quinone formulation for flow batteries is derived from relatively inexpensive and abundant dyestuff chemicals. He says the process for creating the organic battery material does not produce any chemical waste.

Right now, Quino is simply swapping out vanadium-based electrolytes in commercial flow batteries with its quinone formulation, the source of its intellectual property. The substitution only requires a small modification to the battery’s membrane. Ultimately, Beh wants to be able to produce complete flow battery systems because the economic margins will be better; however, he said that one of the challenges of creating and commercializing flow battery formulations is making them unique enough to be patented.

“We are very open about what exactly our secret sauce is made off,” Beh said. “We have the luxury of being the pioneers of using organic molecules for flow battery cells. So, we have some very strong IP, which has already been granted. And it’s enforceable.”

Beh said the company plans to move its production facilities to Houston, TX, later this year to scale up to MWh-day production in preparation for pilot projects it will announce later. Higher-rate production is expected to reduce costs and make the flow batteries cheaper than vanadium formulations at commercial scale.

Once Quino achieves commercial production, Beh says the company’s organic flow battery will be more attractive than lithium-ion batteries in 8-hour to 24-hour storage applications typical of grid and large industrial requirements. He predicts they will cost half as much and will have three times the battery life with the same cycle rates.

Alternative formulations for flow batteries are coming to market, promising more competition and possibly wider commercial acceptance of the technology. Germany-based CMblu Energy recently announced it is supplying its SolidFlow batteries to Mercedes Benz and utility-scale pilot programs in the U.S.

The energy transition from fossil fuels to non-emitting sources, such as renewables and nuclear power is only in its early stages and the effects on policy and energy infrastructure are already massive.

One aspect of the transition has become clear: Retreating from baseline generation in favor of intermittent sources such as solar and wind generation is going to require tremendous increases in long-term energy storage capacity beyond traditional physical means, such as pumped hydro and flywheels. For renewable energy sources, the killer app is battery storage. This is true on a worldwide basis.

The International Energy Agency (IEA), a global organization that monitors energy policy and technology developments for governments and industry, has released a report saying batteries are absolutely essential to the energy transition and represent the fastest growing energy technology in 2003, when the latest data were compiled.

More specifically, battery storage for the power sector was the top growth area, with deployment more than doubling from 2022. The report said this growth was strong across generation categories: utility-scale battery projects, behind-the-meter storage, mini-grids and residential solar systems. Together, these applications added 42 GW of battery storage capacity globally, the report said.

While consumer demand and other applications remain strong, the IEA said 90% of annual lithium-ion battery demand in 2023 came from the energy sector. This is up from 50% 2016, when the total lithium-ion battery market was 10-times smaller. The report said that despite demand, performance and supply chains for lithium-ion batteries have increased to keep pace with requirements.

According to the IEA, expansion in EV sales have not diminished the availability of lithium-ion batteries for other sectors. Lithium-ion chemistries represent nearly all batteries in EVs, the report said.

The one fly in the ointment is that while the demand for battery storage for energy and EVs is essentially global among developed countries, the supply of dominant lithium-ion batteries is very concentrated.

The report says:

While the global battery supply chain is complex, every step in it – from the extraction of mineral ores to the use of high-grade chemicals for the manufacture of battery components in the final battery pack – has a high degree of geographic concentration. Battery manufacturers are dependent on a small number of countries for the raw material supply and extraction of many critical minerals. China undertakes well over half of global raw material processing for lithium and cobalt and has almost 85% of global battery cell production capacity. Europe, the United States and Korea each hold 10% or less of the supply chain for some battery metals and cells today.

Image: CC BY 4.0. 

Tier 1 defense industry contractor RTX (formerly Raytheon) signed a deal with Engie North America to purchase 100% renewable energy in its quest to reduce emissions 46% by 2030 from 2019 levels.

The deal involves buying a mix of wind and solar sources through renewable energy certificates as well as direct energy purchases, all originating in the state. The clean energy will reportedly power 12 of its facilities in Texas.

While the companies did not report the dollar value of the deal, they did say RTX would receive 1.5 million MWh of renewable electricity over the next 10 years, reducing the company’s carbon emissions in Texas by 560,000 metric tons of CO2 over the lifetime of the agreement, which is scheduled to run through 2033. RTX’s Raytheon facility in McKinney, Texas is expected to consume more than 55% of the total clean energy procured.

Initially, the deal includes RECs from Engie’s existing Priddy Wind Project for a portion of RTX’s forecast load in 2024. The remainder of its load for 2024 and beyond reportedly will be sourced with electricity and RECs from several Engie renewable electricity projects in Texas, primarily new projects.

California-based Trio (formerly Edison Energy) is RTX’s energy advisor on the Engie deal. Joey Lange, senior managing director at Trio, said the agreement is notable for a number of reasons, including its size and the fact that it involves RECs and direct purchases of electricity. Also important is the fact that it will spur future development of renewable energy projects.

“This specific engagement is a little unique because it’s going to be a mix of already built assets and projects that are not online yet,” Lange told pv magazine USA. “The use of existing generation is going to allow RTX to hit its goals of a 10% reduction in carbon by 2025. The ramping up of new projects will enable it to reach 46% by 2028 and then extend through 2033.”

Lange said Trio’s role is to help its client, always the energy buyer, to achieve its corporate goals with regard to renewable energy and CO2 emissions reductions. He explained that the deal with Engie in Texas worked because of the concentration of RTX facilities there and the fact Engie has a nice combination of a deep bench of projects available and in the development pipeline.

The deal with RTX means that many projects will now go forward sooner rather than later. “Without that off-taker, the developer is not going to get the hundreds of millions of dollars they need to actually build the project,” Lange said.

Although Engie already has many projects both built and in development in Texas. For example, late last year, Engie inaugurated its 250 MW Sun Valley Solar project in Hill County, Texas, which incorporates 100 MWh of battery storage. It also has the 260 MW Sypert Branch solar project under development in Milam County, Texas. In 2022 the company acquired a 6 GW portfolio of late-stage projects across ERCOT, PJM, MISO, and WECC regions. The acquisition included 33 projects, comprised of about 2.7 GW of solar with 700 MW paired storage, and 2.6 GW of standalone battery energy storage.

The Coalition for Green Capital (CGC), a non-profit group focused on generating financing for climate technologies and clean energy projects, says public and private investments in its network increased over 50% in 2023 to $7 billion compared to $4.6 billion in 2022. The preliminary figures will be amended in the 501(c)(3) organization’s forthcoming annual report.

The CGC does business as the American Green Bank Consortium (AGBC), which consists of over 40 green banks and financing entities.

According to the preliminary reporting, which represents data from about half of the AGBC network accounting to date, $2.5 billion of the 2023 investments were from the members’ own capital, while $4.5 billion came from private capital they attracted. Reed Hundt, CGC’s founder chief executive officer, said in a statement that he expects total investment will reach $10 billion for last year when all data are reported.

Cumulatively, the organization says it has helped attract $21 billion in investment since 2011. It was founded in 2009 with a mission to address climate change by attracting investment in clean power and related technologies.

Rather than directing the financing to individual projects, the CGC works to promote so-called green banks in individual states, which in turn work to attract investors in projects and technologies. For example, the affiliated CGB Green Liberty Notes LLC, a subsidiary of the Connecticut Green Bank, recently announced a new offering in its crowdfunding campaign to attract investments that has enabled small businesses to take out $100 million Small Business Energy Advantage loans.

Such loans are part of a Connecticut program to encourage small businesses to modernize their facilities to improve energy efficiency and use of green energy. For example, the U.S. Environmental Protection Agency announced selectees that will receive $7 billion in grant awards through the Solar for All program to develop solar projects for those who might not be able to buy PV installations themselves. The role of the green bank in this case is to alert financial institutions that the government program exists and that a reliable entity is on hand to assure that investment.

Bryan Garcia, CEO of the Connecticut Green Bank and also chair of the CGC, told pv magazine USA that green banks are essential for pairing funded government clean-energy programs with public and private lenders that might otherwise be wary of the risk.

“The impetus is really around enabling ambitious public policies like, for example, a zero-emission renewable energy credit for commercial solar, to be affordable and accessible to everyone, even renters,” Gacia said. “How do you make the benefits of clean energy technologies affordable and accessible to everyone?”

Risk, as it turns out, is the operative word. Burt Hunter, chief investment officer of the Connecticut Green Bank, told pv magazine USA that organizations like green banks bridge the gap between government opportunities and private investment. If private lenders might balk at the apparent risks of backing clean energy projects, especially for underserved communities, green banks exist to reduce the risk.

“I think what we’ve discovered is that the reason things work so well in Connecticut is we have the right policies to provide the framework that encourages investment in clean energy,” Hunter said. “Investors are pretty straightforward. They just want to know that they’ll be able to get returns, and they also want to know that the rules won’t be changed too much to the detriment of the money that they’ve put out the door. So, it’s not a lot to ask.”

If green banks work to fulfill state policies with regard to clean energy development, might the concept work at the national level? Garcia says the CGC, which he describes as a “chamber of commerce” for state-level green banks, would support a national version of the institution.

The organization says it is seeking a total of $11.9 billion through the U.S. Environmental Protection Agency’s Greenhouse Gas Reduction Fund programs to establish a national green bank. The non-profit is currently active in 40 states. With a national reach, the CGC says it could expect to attract $35 billion in cumulative private-public investing in the first year of inception.

CMBlu Energy AG said it has received an order from Mercedes Benz to provide its SolidFlow battery for the carmaker’s plant in Rastatt, Germany. The 11 MWh installation, planned for the second quarter of 2025, will be paired with the facility’s existing solar array.

The CMBlu SolidFlow battery storage system is a development of the flow battery concept, which offers an alternative to lithium-ion batteries and can be scaled for industrial and utility grid energy storage. Flow batteries have tanks of electrolytes, one positively and the other negatively charged, that are pumped into contact with a membrane that collects discharged electricity or charges the system, as required.

Giovanni Damato, president of CMBlu’s U.S. operations, told pv magazine USA that the company’s SolidFlow design incorporates materials that lower the cost and improve the performance of the system. Typically, flow batteries use vanadium in their electrolyte storage that is expensive and sourced from mines in China, Russia and South Africa. The SolidFlow batteries use carbon as a storage medium.

“That’s where we differentiate ourselves from most flow batteries, where in the tanks are typically just liquid electrolyte and can be quite large for long-duration storage,” Damato said. “Whereas we have stationary solids in the tank as well, which improves our energy density. We can have smaller tanks that have a smaller installed footprint.”

One of the attractions of flow batteries is that they do not use lithium, which according to the International Energy Agency is in very high demand for EV batteries, making lithium-ion batteries expensive for industrial and grid energy storage without significant future increases in mining operations around the world. Damato said Mercedes was looking for alternatives to lithium batteries and to extend the hours of storage coverage.

“The key points are that they wanted to move to a sort of a 24/7 renewable model, like the Googles and the Amazons of the world, where they’re using the renewable energy at the time that they need it,” Damato said.

Ideally, Mercedes would rely on its PV installation for onsite electricity needs, charging the flow batteries with surplus for use at night. Damato said the SolidFlow system can meet the company’s requirements for six hours of stored energy and scale up in the future.

“With our modular form factor, we can easily go a from five- or six-hour base up to a 10- or 12-hour base,” he said.

CMBlu characterizes its flow battery system as “organic,” which is another way of saying it uses carbon. The carbon in the system is readily sourced and easy to recycle. Furthermore, the company is eying long-duration and high-density energy storage applications up to the GWh and says its choice of materials and design form will support this strategy.

Damato said the company came through a 10-year research and development effort and is working on pilot projects in Europe and the U.S. The U.S. project is in conjunction with U.S. Department of Energy’s Argonne National Laboratory (Argonne), along with Idaho National Laboratory (INL) in which the researchers intend to validate CMBlu’s long-duration energy storage system. The goal is to improve microgrids in cold climates and make fast charging of electric vehicles more affordable in underserved communities.

The company also has active projects with WEC Energy Group in Wisconsin and at the Salt River Project in Arizona.

CMBlu was among the winners of the 2018 pv magazine Annual Award for its organic flow battery tech.

Written by Michael Puttré, a freelance technology writer.