Bloom Energy is going to be working with oil and gas company Shell to study how the former’s proprietary hydrogen electrolyzer technology could offer decarbonization solutions. 

The two companies are aiming to develop replicable, large-scale solid oxide electrolyzer systems to generate hydrogen that will then be used by Shell – a technology that “could represent a potentially transformative moment for opportunities to decarbonize several hard to abate industry sectors,” according to K. R. Sridhar, founder, chairman, and CEO of Bloom Energy.

“Green” hydrogen is generally defined as hydrogen produced using renewable energy and water electrolysis technology, as opposed to other forms of hydrogen that are derived from fossil fuels. 

Bloom’s electrolyzers are manufactured in California and Delaware, and can be used for many industrial applications, such as refineries, ammonia, steel processing and cement plants, Rick Beuttel, the company’s vice president, hydrogen business, told pv magazine USA. 

“Currently in the United States, the industrial sector contributes a significant amount of carbon emissions. They need innovative new technologies to help them decarbonize some of their processes, where electrification is not readily available or even feasible,” Beuttel said. 

That’s where green hydrogen could come in. The American green hydrogen industry has seen strong policy support this year, due to its role in providing long-duration energy storage capabilities as well as potentially decarbonizing industries that would be hard to electrify. A report from the Deloitte Center for Sustainable Progress released last June took a closer look at the potential of green hydrogen to meet the demands of heavy industry, and found global market milestones of $642 billion by 2030 and $1.4 trillion by 2050.

However, green hydrogen production is expensive, said Beuttel, and government policies and  regulations help to enable the green hydrogen market and drive down production costs to provide solid business cases for companies to make investment decisions in green hydrogen projects.

In this context, Beuttel noted that Bloom Energy’s technology is 15% to 30% more efficient than competing, low-temperature technologies – and with electricity accounting for around 70% of the cost of producing green hydrogen, “solid oxide technology will make a meaningful improvement in driving down the cost of green hydrogen and helping to decarbonize heavy industry, transportation, and produce the liquid fuels of the future with no carbon footprint,” he said. 

Scaling up electrolyzer capacity will be a key part of growing the green hydrogen industry in the U.S.; a large chunk of electrolyzer production is currently outsourced to manufacturers overseas, experts say, and one of the key challenges to bringing more of that manufacturing capacity back to the U.S. is finding the capital needed to build infrastructure. 

Last May, Bloom Energy launched the world’s largest solid oxide electrolyzer installation at a research facility in California, a unit that the company says produces up to 25% more hydrogen per megawatt than other commercially demonstrated, lower temperature electrolyzers. The 4 MW electrolyzer system was installed and brought online in two months, and has the capability to produce over 2.4 metric tons per day of hydrogen.

Maryland’s largest utility, Baltimore Gas and Electric (BGE), has turned to a 2.5 MW/9.74 MWh battery energy storage system to meet high electricity demand during the winter months in Fairhaven, located just south of Annapolis.

The battery system, which is installed at the Fairhaven substation near Chesapeake Bay and began operating in November, is built largely with Hitachi Energy products. It has two battery containers with 48 racks of lithium-ion batteries, the company said, as well as a control system and two new distribution transformers. 

The Fairhaven energy storage system was installed to solve a very specific reliability challenge in BGE’s footprint – unlike the rest of Maryland, which tends to see peak electricity demand during the summer, Fairhaven experiences a winter peak due to the usage of electric heaters. Because of this, the area’s total electricity load sometimes topped the capacity of the 34.5kV line in the region. 

The new storage system helps address that issue by absorbing energy during times of low electricity demand and then discharging it back to the grid when demand increases. The battery system also allowed BGE to avoid the costs of upgrading some 10 miles of electric distribution infrastructure, according to Hitachi. And after the winter months, when it’s most needed, it can also participate in regional transmission organization PJM’s footprint.

“Participating in these sorts of markets can also help companies align with broader energy goals. Battery projects like the Fairhaven BESS contribute to grid stabilization, offering rapid response capabilities that are crucial for balancing supply and demand,” a Hitachi Energy spokesperson told pv magazine USA. 

More broadly, energy storage plays an important role in ensuring reliability throughout different U.S. markets, including the PJM region, which includes 65 million people spread across 13 states and the District of Columbia, the spokesperson said. 

“As the energy landscape evolves, the strategic deployment of [battery energy storage] technologies not only optimizes existing infrastructure but also fosters a resilient grid capable of adapting to changing demands, unforeseen events such as extreme weather, and the increasing prominence of renewable energy sources,” they added. 

Maryland is aiming to deploy 3,000 MWh of energy storage resources by 2033, and the Fairhaven project is part of this goal, per the 2019 Maryland Energy Storage Pilot Project Act. BGE also deployed a separate battery project in the region – a 1 MW/2 MWh battery located in Chesapeake Beach – in January, 2023, also aimed at shifting energy to times when electricity demand is highest, especially in the winter months. 

Both residential and grid-scale energy storage installations are growing across the U.S. A recent report from Wood Mackenzie and American Clean Power Association (ACP) found that the industry installed 13.5 GWh of storage in the first three quarters of 2023, compared to 12 GWh for all of 2022. This figure that could have been much higher, were it not for some 80% of projects in the pipeline being delayed. 

Utility-scale energy storage company Energy Vault has begun constructing what will be the largest green hydrogen long-duration energy storage project in the U.S., located in Northern California.

The green hydrogen and battery storage facility, which will be able to provide 293 MWh of energy, is being built in the city of Calistoga, in utility Pacific Gas & Electric’s service territory. Calistoga is especially prone to public safety power shut-offs – that is, proactive outages that the utility deploys when weather conditions increase the risk of wildfires caused by its power lines. PG&E’s infrastructure has been linked with multiple wildfires in Northern California and in 2019, the company filed for Chapter 11 bankruptcy as a result of these liabilities.

The Calistoga Resiliency Center, as the project is called, is expected to be completed by the end of Q2 2024, at which point it will be “the first-of-its-kind and the largest utility-scale green hydrogen energy storage project in the United States,” according to Energy Vault. The facility will essentially replace the diesel generators that PG&E currently uses to maintain back-up power in the region during wildfire-related outages. It will be able to power downtown Calistoga and the areas immediately around it, including critical facilities like fire and police stations, for up to 48 hours.

Since this project is a first-of-its kind, it required specific design and engineering capabilities, according to Marco Terruzzin, the company’s chief product officer.

The new facility’s “innovative design is an example of two proven technologies – hydrogen fuel cells and batteries – being used in concert on a single site to provide high-quality emission-free power,” Terruzzin told pv magazine USA.

The facility will operate independently from the wider grid, meaning the fuel cells and batteries must work together to provide a ‘grid-forming’ electricity supply which must reach instantaneously to the demands of the Calistoga microgrid and increase or decrease power output accordingly, he added.

“Deploying cost-effective, next-generation energy supply and long-term storage technologies is essential to ensuring grid reliability and to achieving PG&E’s goal of a net zero energy system by 2040,” Mike Delaney, PG&E’s vice president of utility partnerships and innovation, said.

Under the companies’ 10.5-year agreement, Energy Vault will own and operate the center, providing PG&E with dispatchable power. The company plans to use its energy management system, dubbed VaultOS, to optimize the project’s operations.

The California market is particularly appealing to Energy Vault when it comes to ultra-long duration energy storage solutions because of the increased risk of prolonged wildfire-related shutoffs, Terruzzin said.

More broadly, the company is seeing an increased interest in the use of green hydrogen in utility-scale microgrids from utilities looking for configurations similar to the one being constructed in Calistoga, as well as from the public and private sectors interested in multi-day resiliency solutions, he added.

“We expect that interest to increase as customers shift their focus from simple [power purchase agreements] to 24/7 PPAs that match their electric power hour-by-hour with the electricity being generated in the region in which the customer’s electric load is located,” he said.

Software company WeaveGrid has begun working with Toyota Motor North America to better integrate Toyota and Lexus battery electric vehicles (EV) and plug-in hybrid electric vehicles into the grid in certain utility service territories in the U.S.

Under the partnership, certain models of Toyota and Lexus electric vehicles will be combined with WeaveGrid’s intelligent software platform, which the company says will allow vehicle owners to save money and offer utilities EV load management capabilities. 

“The result is a system that enables drivers to opt into charging optimization, personalized driver insights, and home charging cost savings,” according to WeaveGrid. 

The partnership currently exists in WeaveGrid’s utility programs in Michigan, Maryland, California, Colorado, New Mexico, and Minnesota, Kendall Cody, senior manager, marketing and communications at WeaveGrid, told pv magazine USA.

“As WeaveGrid launches more managed charging programs with our utility clients, Toyota vehicles will be eligible for those programs as well. We cannot say more about which markets at this time as those programs have not yet launched,” Cody added. 

Vehicle owners who participate in the program can earn direct incentives and other benefits from their utility. For example, in Xcel Energy’s footprint in Colorado, Minnesota, and New Mexico, enrolled customers can receive both a $50 bill credit annually, as well as savings from off-peak rates. Meanwhile, in Maryland, Baltimore Gas & Electric enrolled customers could save some $150 annually. The program enables participating customers to save money by helping them to charge during off-peak hours, according to Cody. 

WeaveGrid has worked on similar projects before. Last July, for example, it announced a platform to support Detroit-based utility DTE Energy’s Smart Charge program, which helps EV drivers manage their charging in a way to reduce stress on the grid. Under that program, EV drivers can receive $50 in initial incentives and another $50 in end-of-program incentives from the company. In November 2022, WeaveGrid announced it had raised $35 million in a Series B funding round led by Salesforce Ventures, following its $15 million Series A a year and a half previously. 

The EV market has seen huge growth in recent years, and sales have more than quadrupled during the Biden-Harris Administration. Private companies, meanwhile, have announced more than $155 billion in the EV and battery supply chain. Last month, the administration announced grants worth $623 million to build an EV charging network across major U.S. travel corridors, aiming to install at least 500,000 publicly available chargers by 2030. 

More broadly, the influx of EVs on the road will increase overall electricity demand, Cody said. EV adoption is often clustered, meaning multiple EVs plugging in on a single residential street or neighborhood can create challenges for the local electricity distribution system. And adding a Level 2 charger at home can add two to three homes worth of demand to the grid and accelerate wear and tear on assets like transformers that already have backlogged supply chains, she added. 

On the other hand, utilities can take advantage of these EVs to manage load in their service territories, through managed charging solutions, which can optimize charging so as to reduce strain on the distribution system and turn EVs into grid assets to help balance electricity demand. 

The biggest challenge will be with the distribution system and ensuring the grid stays resilient amidst the challenges and opportunities presented by electrification and decarbonization.

“Funding mechanisms like [Grid Resilience and Innovation Partnerships] and other grants are really good initiatives. Policymakers should also be encouraging good grid planning and forecasting and utility managed charging programs,” Cody said. 

The California Energy Commission has officially greenlighted a $1.9 billion investment plan to build out electric vehicle charging and hydrogen refueling infrastructure in the state.

The plan, which falls under the commission’s clean transportation program, outlines investments for charging and refueling infrastructure for light, medium, and heavy-duty zero-emission vehicles in California – “creating the most extensive charging and hydrogen refueling network in the country,” according to the agency.

The money comes from the $48 billion California Climate Commitment, a comprehensive climate plan pitched by Gov. Gavin Newsom, which includes a $10 billion carve out to decarbonize the transportation sector. With the latest funding, state regulators expect to install 40,000 new chargers across the state, on top of the 94,000 public and shared private chargers that have already been deployed. In total, California is set to install some 250,000 chargers over the next few years, when taking into account previous funding plans, federal funding and other utility programs.  

The funds, which span 2023 to 2027, include $657.6 million for light-duty electric vehicle charging infrastructure and $1.02 billion for zero-emission truck and bus infrastructure. In addition, $130 million is earmarked for zero-emission port infrastructure, and another $5 million for workforce development in the zero-emission vehicle space. The funds will be made available over the next four years and projects can apply for them through competitive grants. 

The investment plan also has a heavy focus on equity, with at least half of the funding going to benefit “priority populations.” Regulators need to ensure that the state’s zero-emission refueling infrastructure is for everybody, Patty Monahan, lead commissioner for transportation with the CEC, said. 

“By investing a bulk of funds to benefit low-income and disadvantaged communities, the state is making sure communities most in need have better access to chargers and less pollution from trucks and buses,” she added. 

At the same time, regulators in California are facing a tension between rapidly deploying zero-emission vehicle infrastructure and ensuring that it’s grid friendly. 

“It costs more to make it grid-friendly – pairing it with solar-plus-storage means you build less chargers,” Monahan said, during a commission business meeting. 

“I will say that this is a tension that we face, because we need to build as many chargers as we can as fast as we can… and we need to be attentive to the grid at the same time. So we’re trying to juggle these two,” she added. 

In fact, without proper resource management, California utilities might need to spend up to $50 billion to prepare their distribution grids for a high level of EVs, electric heating in buildings, and other distributed energy resources by 2035, a study by power software and consultancy Kevala, Inc., conducted for the California Public Utilities Commission concluded last May. The study found that electrifying more end uses would drive up peak load, thereby necessitating grid capacity upgrades. 

Transportation electrification, in particular, drove a significant portion of the distribution grid impacts, the study noted, and the costs associated with preparing the grid for the influx of zero-emission vehicles will “escalate in earnest in 2030 and dramatically increase by 2035 regardless of scenario.”

Around 26% of energy storage systems that were inspected by Clean Energy Associates (CEA) during a recent survey showed quality issues connected to their fire detection and suppression systems, according to a report from the clean energy advisory company.

The findings led the report’s authors to conclude that thermal runaway still poses a significant risk to the energy storage industry. In addition, the survey found 18% of the energy storage systems had issues with the thermal management system. 

“Fire suppression and thermal management systems are critical for functional safety, and defects in these systems can lead to increased risk of fire,” the report said. 

CEA conducted more than 320 inspections on over 52 battery energy storage system factors, collectively auditing over 30 GWh of lithium-ion battery storage projects. In total, the exercise identified more than 1,300 manufacturing issues, the company reported. 

Markets in the U.S. and across the world have been deploying increasing amounts of energy storage to help smooth out renewable power. In fact, the total amount of energy storage installed in the U.S. in the first three quarters of 2023 exceeded total deployments for the previous year, and would have been much higher, if it weren’t for delays that affected 80% of projects in the pipeline, according to a report from Wood Mackenzie and the American Clean Power Association (ACP).

Experts say that multiple factors are driving the battery storage market, including price declines. Median prices for grid-scale lithium-ion battery storage systems shrunk 23% quarter over quarter, according to the report, thanks in part to easing supply chain challenges and lower commodity prices. 

However, policy-makers are also keeping a close eye on the risks posed by lithium-ion batteries, which have been known to cause fires – such as the 2019 McMicken fire at an Arizona Public Service (APS) system, which injured eight firefighters and a policy officer. Last September, a fire occurred at a battery storage in northern San Diego County, California – the Valley Center Energy Storage Facility, a 139 MW project. That fire necessitated evacuating people from homes and businesses within a quarter mile of the storage system’s site. 

CEA’s analysis took a closer look at issues at the system, module and battery cell levels. It found that some 50% of quality assurance findings were system-level defects. Two factors drive this trend, according to the report: systems tend to be complex and vulnerable to problems that were actually caused further upstream and escaped earlier quality checks, and the integration process for battery storage systems tend to be highly manual and labor intensive, and don’t always have stringent quality control procedures.

“A takeaway is there is no perfect production line or supply chain or manufacturer… So definitely doing due diligence before procuring and then in the factories is a must for buyers. The industry has matured a lot, but it’s not there yet – I think that’s quite obvious,” said George Touloupas, senior director, technology and quality with CEA, during a webinar conducted by Energy-Storage.news.

But while lithium-ion batteries present these risks, Touloupas said they remain the prominent storage technology being purchased today.

“[I]f we need a lot of hours of storage, then maybe flow batteries or other technologies become competitive – but as we are today, there’s nothing else than lithium-ion,” he said, adding that he’s optimistic that the industry is reacting and addressing these safety challenges. 

Noah Roberts, senior director of energy storage with the American Clean Power Association, noted that the report’s findings do not mean that these faults exist in energy storage facilities connected to the grid. In fact, he said, under current industry standard practices, and the nationally recommended safety standard, NFPA 855, all of the faults identified in this report would be corrected during the project installation and commissioning process.

“It is critical that the topic of this report—a subjective evaluation of manufactured products still on the assembly floor—is not conflated with the highly regulated, evaluated, and tested energy storage equipment currently serving the electric grid,” Roberts added.

This article was amended on Feb. 19, 2024 to add comments from Noah Roberts of the American Clean Power Association.

Electrolyzer manufacturing capacity could outstrip demand by two times by the end of a decade, according to a new report from Clean Energy Associates.

The report, which looks at the technology trends and policy impacts in the green hydrogen space, forecasts that global manufacturing capacity for green hydrogen will touch 54 GW by 2027. China is likely to account for almost half of that global capacity, and when combined with North America and Europe, will reflect some 93% of the electrolyzer capacity global market share, its authors noted. The country currently accounts for 61% of manufacturing capacity across the world, due in part to a complete supply chain and relatively low costs. 

However, especially given the passage of the Inflation Reduction Act in the U.S. and the policy support that provides the green hydrogen sector, North American manufacturing capacity is also set to rapidly grow, the report noted. 

While hydrogen can be made using multiple raw materials, including coal and natural gas, green hydrogen – that is, hydrogen produced with renewables – has increasingly become a priority for the U.S. as a potentially critical part of the clean energy transition. Green hydrogen is made by electrolyzing water using renewable energy like wind or solar. 

The report also compared different electrolyzer technologies, including alkaline and proton exchange membrane (PEM). It estimates that alkaline electrolyzers, which are largely clustered in China and Europe, will remain the most prevalent technology over the next decade, thanks in part to lower costs and the potential for efficiency improvements. PEM electrolyzers, meanwhile, are manufactured more globally but depend on electrodes that use rare materials, which could be a potential challenge.

While the report estimated that electrolyzer manufacturing capacity could outpace demand by 2030, it also noted that the actual usable capacity is likely to be less than nameplate capacity.

“The forecasted electrolyzer demand is highly uncertain, as it can be affected by policy implementation, downstream industry developments, low-cost renewable energy availability and operation of existing projects,” the report said.  

The industry as a whole has been focusing on the issue of ramping up electrolyzer manufacturing capacity. One of the key challenges it faces in doing so is accessing the necessary capital – however, a couple of announcements last year indicate that trend could be changing. For instance, Verdagy revealed plans to open a new plant in Newark, California, early this year to build large volumes of advanced water electrolyzers. 

Electrolyzer manufacturer Electric Hydrogen, meanwhile, completed an oversubscribed $380 million Series C financing. The company is building a 1.2 GW facility to produce commercial electrolyzer systems in Devens, Massachusetts, with deliveries expected later this year. 

Some experts are also looking at alternatives to the rare materials used in PEM electrolyzer technology – like clean chemistry company Mattiq, which announced in October that it is developing a portfolio of alternatives to iridium, one of those materials. According to the International Renewable Energy Agency, the current iridium production levels could support manufacturing some 3 GW to 7.5 GW of electrolyzers every year. Mattiq, however, is looking at alternative catalysts that could be used in these electrolyzers instead. 

Nikola Corporation, a manufacturer of heavy-duty battery and fuel cell electric vehicles, has opened the first in what will become a network of hydrogen refueling stations in Southern California.

The station, located in Ontario, Calif. is part of Nikola’s HYLA brand and can fuel up to 40 of the company’s hydrogen fuel cell electric Class 8 trucks every day. Nikola is aiming to build a network of up to 60 such hydrogen fueling stations over the next few years, and plans to have nine up and running by the end of the second quarter of this year. 

While the Ontario station is part of a private network at this point in time, the company is designing the HYLA stations to accommodate all 700-bar Class 8 OEM trucks, Ole Hoefelmann, Nikola’s president of energy, told pv magazine USA. 

The process of launching this first refueling station has also provided the company with lessons learned, according to Hoefelmann. For instance, “it is beneficial to bring city government officials like city planners and fire departments to the project discussion as early as possible. They are great partners and most interested in bringing low emissions solutions to their communities,” he said. 

The Arizona-headquartered company began serial production of its hydrogen fuel cell electric truck last summer and has also seen some regulatory support, receiving a collective $58.2 million from regulatory agencies last year to build out its network of heavy-duty truck hydrogen refueling stations. The largest of these was a $41.9 million grant from the California Transportation Commission and California Department of Transportation, aimed at constructing six hydrogen refueling stations in Southern California. Also last summer, the company announced a voluntary recall of more than 200 Class 8 Tre battery-electric vehicles, following a fire that affected multiple trucks at its headquarters in Phoenix. 

Now, Nikola is focused on securing a robust supply chain and refueling infrastructure for hydrogen, which it sees as important to bringing more hydrogen fuel cell electric trucks onto the roads. The company expects that once it has completed bringing nine refueling stations online in the next few months, it will have one of the largest heavy-duty hydrogen refueling networks in the world. 

As of 2023, the U.S. had 59 retail hydrogen refueling stations, mostly in California, but few were equipped to cater to heavy-duty vehicles. But the U.S. is currently leading the development of new technologies and protocols to fulfill the heavy-duty transportation requirements, Hoefelmann said, adding that in the coming months, the company expects to see some of those innovative solutions on the field. 

Other companies are also taking a closer look at hydrogen refueling capacity. In 2022, Daimler Truck North America, NextEra Energy Resources and BlackRock Renewable Power entered a memorandum of understanding, with a $650 million initial investment, that included looking at building out charging infrastructure for medium- and heavy-duty battery electric and hydrogen fuel cell vehicles. 

However, one challenge companies in the space continue to face regards permitting processes, and obstacles like extensive waiting times or unclear process streamlines continue to discourage the infrastructure developers, Hoefelmann added. 

California lawmakers have provided one good example on how to deal with that: Senate Bill 1291, passed in 2022, requires all California cities and counties to develop and expedite, streamlined permitting processes for hydrogen fueling stations, Hoefelmann said. 

A combination of battery storage and hydrogen fuel cells can help the U.S., as well as most countries, transition to a 100% clean electricity grid in a low cost and reliable fashion, according to a new report from Stanford University.

The report, published in iScience, took a closer look at the costs involved with ensuring a reliable grid in 145 countries, that used renewable energy – including solar, wind, hydroelectric and geothermal resources – to power their grids, transportation, buildings, industry, agriculture, forestry, fishing and the military. The main energy storage options it took into account included hydropower, batteries and green hydrogen, which is produced using renewables. 

The study found that transitioning to clean energy could enable these countries to achieve overall annual energy cost reductions of around 61%. 

“The first step is to electrify all energy sectors as much as possible… the efficiency of electricity over combustion reduces energy demand by 38.0%,” when averaged over 145 countries, Mark Z. Jacobson, the author of the study and professor of civil and environmental engineering at Stanford University, told pv magazine USA. 

The second step is to provide the electricity with just wind-water-solar sources and storage, and eliminating energy to mine, transport, and refine fossil fuels and uranium saves another 11.3% of all energy worldwide, he added. End-use energy efficiency improvements beyond business-as-usual reduce energy requirements another 6.6%, and a forecasted reduction in the cost per unit of energy of about 9% results in an overall annual cost savings to a country of 61%. 

The study will help electricity system planners create a more efficient and cost-effective future energy system based on clean, renewable electricity, Jacobson said.

“The results provide countries with concrete evidence and the confidence that 100% clean, renewable grids not only lower costs but are also just as reliable as the current grid system,” he added. 

The study employed three kinds of computer modeling: a “three-dimensional global weather-climate-air pollution model, a spreadsheet model and a model that matches electricity, heat, cold, and hydrogen demand with supply, storage and demand response assuming perfect grid interconnection,” according to a statement. 

It found that while existing hydropower and batteries can ensure grid reliability, adding green hydrogen to the system can reduce the energy costs in some regions, although a combination of hydropower and green hydrogen with no batteries is always more expensive than a combination of the three. This is because every region with a highly renewable grid will need short-term bursts of power, such as that provided by hydropower or batteries, but not every region necessarily needs the long-term energy storage provided by hydrogen.

Green hydrogen storage can absorb excess electricity when there is too much wind or solar on the grid, and then provide storage on scales of hours to a few days, when wind and solar are not available and hydropower and batteries are depleted, Jacobson said. 

But the technology still faces challenges; like any storage type, up-front cost is always an issue, although the cost benefits are large in comparison, he added. Policy makers can help address these challenges by focusing funding on solutions like battery storage and green hydrogen, rather than on carbon capture, direct air capture, blue hydrogen, non-hydrogen electro-fuels, small nuclear reactors, and bioenergy, Jacobson said.

Crux, a sustainable finance technology company has raised $18.2 million in Series A funding, bringing its total funding to over $27 million.

The company was founded in January 2023 by Alfred Johnson, former deputy chief of staff to Secretary Janet Yellen at the U.S. Treasury Department where he was responsible for work related to digital assets, cybersecurity and technology, and more. He founded Crux to create a market for transactions of the newly transferable clean energy tax credits, included in the Inflation Reduction Act (IRA).​​ The company’s latest round of funding was led by Andreessen Horowitz, and included participation by existing investors including Lowercarbon Capital, New System Ventures, Overture, and The Three Cairns Group. 

“This new round of funding will help us build even faster, grow the transferable tax equity market at a critical moment, and expand our services — furthering our mission of making sustainable finance more efficient and interconnected,” said Alfred Johnson, CEO and co-founder of Crux. 

Specifically, the company said that the new funding will help it grow its team, scale up the volumes of annual transferable credits to the billions and look into other offerings for clean energy projects. 

Prior to the passage of the IRA, developers needed to rely on project finance structures called tax equity partnerships to monetize unused credits, Johnson told pv magazine USA. But the IRA substantially extended and expanded the use of tax credits to catalyze the development of clean energy and decarbonization projects, he added.

“Transferability has significantly increased access to capital for smaller projects and new technologies. Projects below [$50 million] are generally too small to attract a traditional tax equity investor. Now, those projects can sell credits directly to third party buyers,” Johnson said.  

Earlier this month, Crux released its first Transferable Tax Credit Market Intelligence report, which estimated that between $7 billion and $9 billion in transferable clean energy tax credits were transacted in 2023. The transferable sector currently accounts for one-third of the entire tax finance market – estimated at around $23 billion in 2023 – and the report forecast a particularly strong growth for the sector. 

The company has over $8 billion of credits currently available for sale and is working with clients that include project developers, tax credit buyers, banks, and others. 

“Recent policy changes around the transferability of clean energy tax credits have propelled market growth beyond expectations, fundamentally transforming how clean energy and decarbonization projects are financed in the United States,” said David Haber, general partner at Andreessen Horowitz. 

Looking to 2024, Johnson expects that this market will continue to grow and mature rapidly. At a micro level, a large proportion of prospective credit buyers who were not active in the market for tax credits in 2023 expect to get involved this year, he said – and if a large share of those buyers ultimately decide to pursue a deal, that would represent net new demand for tax credits.

“We also are starting to see some of the first deals that blend traditional tax equity partnerships and direct transfers inked. These hybrid deals will be used more frequently, and buyers are already reacting favorably to those credits,” Johnson added. 

At a macro level, he said, the traditional tax equity market is relatively constrained due to a combination of factors. 

In this context, the energy transition will be fueled by a transparent, efficient market for clean energy tax credits, said Johnson. 

“Our platform is one part powerful data, stakeholder, and workflow management software built specifically for tax credit transactions. And, Crux is also the liquidity solution for buyers, sellers, and their intermediaries to transact,” he said. 

Hydrogen company Plug Power launched operations at the largest liquid green hydrogen plant in the U.S., located in Woodbine, Georgia.

The facility has the capacity to produce 15 tons of green hydrogen per day; enough, the company says, to power some 15,000 forklifts daily. It includes eight, 5 MW electrolyzers; the largest such electrolyzer deployment in the U.S., which produce hydrogen. This hydrogen gas is then condensed into a liquid, by dropping its temperature to -423F, at which point it can be routed to hydrogen fueling stations. The facility is located a mile away from highway I-95 and 20 miles away from I-10, giving it easy access to commercial and industrial centers across the country, the company said. 

The hydrogen produced by the new facility will add to the liquid hydrogen deliveries that Plug Power currently makes to its customers for fuel cell electric vehicle fleets, stationary power applications, and other such uses. Liquid and gaseous hydrogen are both expected to positively impact the company’s bottom line, Plug Power said. 

The move comes as interest in green hydrogen grows as a tool to decarbonize specific industries, including heavy-duty transportation, heavy manufacturing and aviation.  

“The hydrogen market in the U.S. is at an inflection point. We expect hydrogen infrastructure and product offerings to vastly expand in the next five years, including increasing commercial uses in hard-to-abate sectors like concrete, steel, glass manufacturing, and more,” Andy Marsh, CEO of Plug Power, told pv magazine USA. 

The company is committed to driving that continued market expansion with the buildout of its North American hydrogen production plant network, strong partners, and expanded electrolyzer production, Marsh added. 

The role of the hydrogen sector in the clean energy transition has been backed by recent legislation, such as the Inflation Reduction Act – and specifically, the clean hydrogen production tax credit (PTC), which Marsh said has the potential to catalyze the domestic hydrogen sector, and drive down costs, allowing the industry to scale in a meaningful way. At the same time, “there are still a lot of outstanding questions on the implementation of the PTC based on the draft guidance the U.S. Treasury Department released at the end of 2023,” he added. 

Now that the Georgia facility is online, the company is looking at building out a green hydrogen network of production plants across the U.S. and has made substantial progress on other U.S.-based plants, including plants in Louisiana, New York, and Texas, Marsh said. 

“All these plants in development will benefit from our experience building the plant in Georgia,” he said. 

At the same time, Marsh noted, government policy support is essential for the hydrogen industry to scale and achieve cost parity with other energy sources. 

“Policymaker guidance on incentives aimed at fostering the clean hydrogen industry must be clear and pragmatic in achieving these aims,” he said. 

Perceptions around large-scale solar project development, and the impacts of the projects, continue to be one of the key concerns that stakeholders keep in mind when thinking of hosting these projects in their communities, according to a new study from Berkeley Lab, Michigan State University, and the University of Michigan.

The study is based on 54 interviews with residents, developers and policy makers, about seven large-scale solar projects in the U.S., defined as ground-mount photovoltaic projects that are equal to or more than 1 MWdc.

The research seeks to address what it calls an important information gap – that is, while rural Americans broadly support large-scale solar, local opposition to proposed projects is also increasing, with developers pointing to community opposition as one of the reasons for delayed and canceled projects. At the same time, there isn’t much data on the perception of these projects among local communities. 

As solar deployments across the U.S. continue to grow – one estimate from the Solar Energy Industries Association (SEIA) and Wood Mackenzie suggests the market is set to triple by 2028, touching 380 GW of installed solar capacity – developers are working to find new locations for projects, including things like underutilized parking lots, timberland and farmland. But developers still face plenty of opposition from local communities who point to blocked views, noise and environmental concerns, among others. 

The new paper essentially tries to answer two questions: identifying the most prevalent concerns that residents have about large-scale solar projects; and looking at what strategies developers and others could employ to improve those perceptions. 

The researchers found that planning processes and local impacts of large-scale solar projects remain a key concern. The seven sites that the study focused on span regions, ownership structures and ecosystems, but all raised concerns among local stakeholders regarding development impacts. Specifically, the authors noted, local residents and officials were concerned about the information provided to them, and their lack of influence on project design. 

The research also produced multiple measures that its authors say could address these concerns. For instance, there is a need to bolster direct engagement between developers and operators of projects, local officials and community members, which should begin earlier and be more frequent and in-person – not just during the development process, but also while the project is in operation or being decommissioned, the report said. The authors stressed the need to go beyond the format of public meetings and town halls, and instead recommended strategies that “stress in-person contact and communication, and presume residents have a meaningful role in influencing project design.”

Developers can also turn to third-party, local intermediaries to liaise with the community and local officials, the report’s authors recommend. In addition, they stress the need to ensure residents are well aware of both the benefits and burdens tied with going ahead, or restricting, project development.

“This included inviting individuals in from neighboring communities that had undergone solar development to share about their experiences, both good and bad, with a focus on the opportunity costs of decisions that in the short-term may be seen as victories for residents, but later may generate regret,” the report stated.

Energy storage and management solutions provider Electriq Power Holdings is gearing up to launch 10 new “sustainable community networks” – programs that incentivize the deployment of solar-plus-battery storage systems – in Los Angeles County.

The program, called the PoweredUp Network, essentially offers qualifying homeowners solar-plus-battery storage systems at zero upfront costs, and without income, credit or property lien requirements. The systems can also help residents reduce electricity costs by up to 20%, access back-up power, and avoid peak pricing periods on the grid, according to the company. 

“Our program is great for low-to-moderate income households because it gives them the ability to install solar + storage because we’ve removed those financial barriers,” said Frank Magnotti, CEO of Electriq Power. 

Electriq Power is aiming to launch the networks by the end of the first quarter, and estimates that around 400,000 residents in Southern California will be eligible for it. 

In November, the company expanded in New England, launching a similar network in the city of Derby, Connecticut to around 3,000 eligible homeowners. The company’s programs could be an especially good fit in areas that have high electricity costs – like Connecticut, where the retail price of electricity is around 10 cents/kWh higher than the national average, as well as other parts of New England, which the company is continuing to consider for additional sustainable community networks. 

California’s three large investor-owned utilities – Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric – have meanwhile seen residential electric rates increase by between 34% to 82% since 2014, according to data from the U.S. Energy Information Administration. The state has also been facing challenges with grid reliability, driven by increasing electricity demand – due in part to severe weather patterns – and the need to meet that demand during the evening hours, when solar power is declining on the grid. 

Electriq Power’s solar-plus-storage systems also have the ability to export back to the grid, according to Magnotti, and the battery component of the system is equipped with operational software using which owners can participate in virtual power plant (VPP) programs – essentially, sending power back to the grid when demand is high, helping to prevent blackouts. 

VPPs are aggregations of distributed energy resources, like rooftop solar, energy storage and demand response efforts, that can be designed to offer additional capacity when electricity demand on the grid is high, providing a potential alternative to natural gas peaker plants. One study, by the Brattle Group, estimates that utilities could see savings of $35 billion by 2033 by using VPPs for peaker capacity. 

Electriq Power reported preliminary fourth quarter revenue results earlier this month, expecting to record around $1.3 million in sales for the quarter, which Magnotti said represented year-over-year growth of over 100%. The company estimates that the Southern California contract could generate incremental “total contract value” – essentially, anticipated revenue over the next three years – of $30 million. The company has also more than 160 signed power purchase agreements via its sustainability community networks, which it says could generate around $5 million in revenue over the first and second quarters of the year. 

A flexible approach to energy will be key as the industry grapples with ongoing reliability challenges, extreme weather, the electrification of different sectors of the economy, and the growth of renewables and storage, a new report from GridBeyond concludes.

The report, which looks at energy trends for 2024, noted that policy-makers around the world are keeping a close eye on energy security and affordability. And while a reduced reliance on imported fossil fuels and increased renewable use can lead to greater energy security and independence, grid operators do have to overcome certain challenges connected to them, such as intermittency. 

The energy sector is on the brink of its next evolution, into a fresh era characterized by an emphasis on sustainability and efficiency, Michael Phelan, CEO and co-founder of GridBeyond, said.

“At the same time, to achieve net-zero emissions, companies are redefining their strategies, embracing a flexible approach to energy utilisation as a core asset in remaining competitive within… this new landscape. Flexibility is key to ensure the success of the energy transition to a net zero future,” Phelan added. 

The energy sector is undergoing many changes, as well as challenges related to reliability. Extreme weather events can lead to increased electricity demand, as well as increase the chance that coal and gas power plants experience breakdowns, the report noted. At the same time, global renewable capacity additions are rapidly increasing, to more than 440 GW in 2023, according to the International Energy Agency. In fact, under an accelerated model, renewable additions could touch 550 GW in 2024, as Europe and other parts of the world look to reduce dependence on Russian natural gas imports, the report noted. 

In this context, energy policy makers across the world are looking to expand energy flexibility on the demand side to help support the grid, the report noted. In a recent GridBeyond survey, 30% of respondents say energy flexibility as the “biggest trend impacting the energy markets of the future” – compared to just 22% a year ago, the report noted. 

“This trend is supported by a series of policy and regulatory developments in markets across the world as grid operators seek new and innovative measures to encourage flexibility in the power system,” according to the report. 

In the U.S., for instance, the Electric Reliability Council of Texas’s (ERCOT) Contingency Reserve Service, a daily procured ancillary service launched in June, is an example of this, and will help keep supply and demand balanced in real time as electricity demand grows. This is the first daily procured ancillary services introduced in the market in more than two decades, the report noted Japan, meanwhile, is set to launch new ancillary services markets in 2024, with rolling weekly and day-ahead markets that can compensate storage. 

Clean energy procurement processes, meanwhile, can be more complex than common forms of procurement today, and buyers will need to be encouraged with the right incentive and reward structures to help undertake them, the report said. 

“In designing new products and services, the incentives offered to the customers providing these services should reflect the value of any grid benefits and increased resiliency that can accrue to utilities, grid operators, or other market participants,” the report stated. 

Owners of electric vehicles (EVs) are more likely to add solar panels to their homes, a new behavioral study analysis from the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) concluded.

The study, funded by the DOE’s Vehicle Technologies Office, was based on a survey of 869 households in the San Francisco Bay Area, first in 2018 and then revisited in 2022. It found that around a quarter of EV owners also own a solar photovoltaic system, while only 8% of people who didn’t own EVs had adopted distributed solar. 

EV owners might have a tendency to also install solar since solar panels could help offset the energy costs of charging their vehicles at home, Shivam Sharda, a computational research scientist at NREL’s Center for Integrated Mobility Sciences, and lead author of the study, said. 

“Both EVs and PVs have a complementary nature, which might play a pivotal role in energy systems resiliency, addressing concerns regarding grid stability and power management strategies,” added Sharda. 

On the flip side, the research found that owning solar panels could also influence whether a homeowner buys an EV, although that correlation is not as strong.  

As of 2021, 3.4% of light-duty vehicle sales in the U.S. represented EVs, and around 6% of homeowners had deployed rooftop solar. As more EVs make their way on to the roads, they will also add to electrical demand. In this context, solar energy could present an important solution. 

Two aspects that could encourage a consumer to adopt either solar or EVs, or both include being cognizant of the technologies, and being social enough to ask about them, the study determined. For instance, if someone has a friend or family member who owns a rooftop solar panel or EV, they become more educated about the technology and its pros and cons, thereby influencing their decisions, Sharda said. 

From a policy perspective, while governments currently incentivize the adoption of both EVs and rooftop solar, the study recommended implementing strategies that could accelerate the deployment of the two technologies jointly.

“Because EV owners are inclined to use PV anyway, such incentives might provide a push for EV owners to adopt solar technology much earlier than what is currently observed. How soon a household adopts cross-sectoral sustainable technologies will play an important role in achieving decarbonization goals,” NREL said. 

The study also highlighted the need for additional holistic surveys to better understand the nexus of transportation and residential energy use. 

A 2021 consumer report from SolarReviews found that an EV would cost about  $1,058 per year when using a public charger, but that costs drop to as little as $415 annually with home solar – compared to the $1,260 a year it costs to fuel a traditional, gas-powered car. The report compared a gas-powered Hyundai Kona with an all-electric one, and found that during a 13,500-mile year, the former would cost $1,260 to fuel, while the latter, when charged at home, could cost around $662 per year in California and $450 annually in a state like Florida. In fact, over a 25-year period, charging an EV with home solar could save the owner some $16,250, the study concluded. 

Alliant Energy has deployed six new solar projects in Wisconsin, collectively amounting to 514 MW and tripling the utility’s solar generation capacity.

All six projects are online and operational, and are single-axis tracker systems, Tony Palese, a spokesperson for Alliant Energy, told pv magazine USA. They include durable, high-performance bi-facial solar panels, which can cope with severe weather conditions, like snow. The sites were constructed beginning in 2022, and employed almost 1,000 workers, according to the utility. 

The projects include the 50 MW Albany Solar Project in Green County; 50 MW Cassville Solar Project in Grant County, 150 MW Onion River Solar Project in Sheboygan County, 65 MW Paddock Solar Project in Rock County, 100 MW Springfield Solar Project in Dodge County and 99 MW Wautoma Solar Project in Waushara County. The modules at the six completed sites are primarily from Trina and First Solar, Palese said. 

Completing these projects is a huge milestone in Alliant Energy’s journey toward a “brighter energy future,” David de Leon, Alliant Energy’s Wisconsin president, said.

“We’re proud to leverage new technology and locally generated energy solutions to increase customer value and help avoid long-term costs,” de Leon added. 

The new batch of projects are among 12 utility-scale solar projects that are part of Alliant Energy’s clean energy blueprint in Wisconsin. The company deployed three projects, amounting to 250 MW, last year, and have three more that are in the final stages of construction. Once all the projects are online – expected to be by mid-2024 – they will collectively generate 1,089 MW.

The company is also making investments in energy storage. Alliant Energy has announced plans to construct battery energy storage systems at two of its solar sites, Palese said,  a 100 MW and 75 MW system that will be constructed at solar facilities in Grant County and Wood County respectively. Last February, the utility also announced plans to deploy a 99 MW battery system adjacent to its Edgewater Generating Station, which is scheduled to retire in 2025.

“We expect to begin construction on all three battery projects this spring,” Palese said. 

In September, Alliant announced it had been selected for an up to $30 million grant from the U.S. Department of Energy’s Office of Clean Energy Demonstrations for a planned 200 MWh energy storage system, with a 10-hour storage duration. The project would use a technology that compresses carbon dioxide gas into liquid to store energy, and then convert that liquid back into a gas to power a turbine, creating electricity when demand rises on the grid. 

The green hydrogen industry in the U.S. saw some strong policy support and a flurry of project announcements this year, as policy-makers and the energy industry eye the resource’s potential to provide long-duration energy storage to the power grid, as well as help decarbonize industries that would otherwise be hard to tackle.

A June report from the Deloitte Center for Sustainable Progress, which looked at the potential of green hydrogen to meet the demands of heavy industry, identified global market milestones of $642 billion by 2030, $980 billion by 2040, and $1.4 trillion by 2050.

Policy support for clean hydrogen 

2023 saw a lot of federal policy support for clean hydrogen technologies. In June, the Biden-Harris Administration put out a national clean hydrogen strategy and roadmap, outlining opportunities for the U.S. to domestically produce 10 million metric tonnes (MMT) of clean hydrogen annually by the end of the decade, 20 MMT annually by 2040, and 50 MMT annually by 2050.

The administration also created an inter-agency hydrogen task force – co-chaired by Mary Frances Repko, White House deputy national climate advisor, and David Turk, deputy secretary of the U.S. Department of Energy (DOE) – to deploy a more holistic, “whole of government approach” to clean hydrogen across the administration. 

And in October, the DOE announced funding of $7 billion to launch seven regional clean hydrogen hubs around the country, each aimed at more broadly supporting the commercial-scale deployment of the resource. The funding for the hubs comes from the 2021 Bipartisan Infrastructure Law. All seven hubs are estimated to produce a joint three million metric tons of hydrogen each year, and slash 25 million metric tons of carbon dioxide emissions every year.

Plans for hydrogen projects

This year also saw some interesting hydrogen project announcements. In October, for instance, Duke Energy announced plans to break ground on the first U.S. demonstration project with an end-to-end green hydrogen production, storage and combustion system, located at its 74.5 MW DeBary solar plant in Florida. The facility – expected to be operational in 2024 – will pull energy from the solar plant and run it through two 1 MW electrolyzer systems to produce hydrogen, which will then be stored until needed. At that time, the hydrogen will be passed through a combustion turbine to create electricity. 

Hydrogen company H2B2 Electrolysis Technologies, meanwhile, is working on its Fresno, California-based SoHyCal project. The project is currently in its first phase, producing up to a ton of hydrogen every day using biogas. In its second phase – expected to begin in the second quarter of 2024 – it will begin using solar energy from a nearby photovoltaic plant, as well as biogas, and ramp up production to up to three tons of hydrogen per day. 

Ramping up electrolyzer manufacturing capacity 

Another focus for the industry this year has been ramping up the manufacturing capacity of electrolyzers, an essential component to producing hydrogen from renewable energy. Experts say most electrolyzer production is currently outsourced to overseas manufacturers, and one of the chief challenges to ramping up domestic manufacturing capacity is accessing capital to build the necessary infrastructure. 

However, some companies are looking to change this dynamic. Verdagy, for instance, announced in September that it is opening a new facility to manufacture advanced water electrolyzers in large volumes in Newark, California. The new plant is slated to begin operations in the first quarter of 2024. 

And Electric Hydrogen – which manufactures 100 MW electrolyzer systems that can each produce nearly 50 tons of green hydrogen daily – completed an oversubscribed $380 million Series C financing this year, bringing the total funding it has raised since its launch three years ago to $600 million.

Cost and scaling obstacles 

But the hydrogen industry still has a way to go. Some analysts, for instance, have raised concerns that the Biden-Harris Administration’s ambitious clean hydrogen goals will require addressing some cost and scaling obstacles. 

Hydrogen produced from fossil fuels currently costs around half of what clean hydrogen does – between $1/kg and $2/kg, compared to $3/kg to $6/kg – and the industry is likely to need continued financing, including through subsidies, to scale up significantly, some say.

Some environmental stakeholders, meanwhile, continue to raise concerns about hydrogen’s role in the clean energy transition. This summer, for instance, a coalition of more than 180 organizations – including conservation, social justice and Indigenous groups – penned a letter to the Biden administration urging it to reject the applications for regional clean hydrogen hubs. 

The groups noted that some 95% of hydrogen produced currently is derived from fossil fuels, and contended that hydrogen infrastructure build-out could lead to additional greenhouse gas emissions, as well as pollution.

Thermal energy storage developer Brenmiller Energy has finished commissioning a bGen thermal storage-based co-generation station at the State University of New York (SUNY) Purchase. It is expected to slash around 550 metric tons of greenhouse gas emissions every year.

The project was developed along with the New York Power Authority and partially financed by a grant from the Israel-U.S. Binational Industrial Research and Development Foundation. Brenmiller intends to hand over the system to the university after training in mid-January. 

The company’s thermal energy storage system essentially uses crushed rocks to store the energy from renewables or the grid, Gideon Sharir, managing director, U.S., at Brenmiller Energy, told pv magazine USA. The system heats this energy to up to 1200°F, via internal heaters, and stores it until it is ready to be discharged on-demand in the form of clean steam, hot water, or air, Sharir said. 

The SUNY system is part of a combined heat and power system. The project charges using electricity via embedded electric heaters and waste heat from the microturbine’s exhaust, and discharges to heat SUNY Purchase’s recreation center, which is one of the campus’ most energy-intensive buildings. 

The project, which “charges” using both exhaust gas and electricity, is a demonstration site that showcases the full array of thermal energy storage capabilities, including its ability to charge with electricity and recovered heat, according to Sharir. It is distinct from the other projects in Brenmiller’s pipeline, which are designed to charge using only electricity from renewables or the grid. As a demonstration project, the SUNY system is relatively smaller in size – 450 kW/400 kWh – although Brenmiller’s other projects typically range from 10 MWh to 100+ MWh. 

Turning over the operation of the project is a huge milestone for the company, said Avi Brenmiller, Brenmiller’s chairman and CEO. 

“The benefits of our bGen, once demonstrated through this project, could enable broader adoption of our thermal energy storage systems in New York and across the U.S.,” Brenmiller said. 

Thermal energy storage can play a massive role in the clean energy transition, according to Sharir. 

Industrial heating demand accounts for about 12% of total U.S. greenhouse gas emissions. Because thermal batteries can reach extremely high temperatures at a cost that is competitive with natural gas, and are mature and reliable, industrial manufacturers are increasingly looking at them as a decarbonization solution, he said. 

“As these technologies continue to gain traction, the thermal energy market is expected to yield trillions of dollars by 2040,” Sharir added. 

However, the technology does face certain challenges to scaling up, including complex and outdated grid policies and supply frameworks, he said. On the one hand, market structures must be updated to take advantage of the benefits of thermal energy storage to reduce stress on the grid. On the other hand, regulators must allow thermal energy storage to participate in wholesale markets and access spot prices, he said. 

“Overcoming both of these barriers will ensure that [thermal energy storage] can provide flexibility to the grid and cost-effectively enable industrial decarbonization,” said Sharir.

Blue hydrogen – a form of the resource produced from fossil fuels, where the carbon dioxide is then captured and stored – could provide a “pragmatic transition” to green hydrogen, and offers an unsubsidized levelized cost that is two to three times lower than that of green hydrogen, but with elevated emissions intensities, according to a new report from Enverus Intelligence Research.

Most hydrogen today is made using fossil fuels, the bulk of which use steam methane reformers, Alex Nevokshonoff, senior associate at Enverus Intelligence Research, told pv magazine USA. This process essentially reacts steam with methane to produce hydrogen, carbon dioxide and carbon monoxide. The hydrogen is termed “blue hydrogen” if the carbon dioxide molecules are then captured and stored, Nevokshonoff said. 

“Although more carbon intensive than green hydrogen production, blue hydrogen projects provide a practical and economical pathway to clean hydrogen adoption,” Nevokshonoff said.

Clean hydrogen could play an important role in decarbonizing the U.S. energy system, as well industrial, chemical and heavy transportation sectors. Hydrogen can also be created by using excess renewable energy, like solar, to run electrolyzers. In August, the Biden-Harris Administration created an inter-agency hydrogen task force to create a “whole of government” approach to deploying the resource. But ramping up the clean hydrogen economy will also depend in part on reducing the levelized cost of solar energy, some experts say. 

Blue hydrogen technologies can currently tap into multiple incentives in the U.S. The 45V production tax credit offers $0.60/kg and $3/kg for hydrogen produced with a carbon intensity lower then 4.0 kgCO2e/kgH2, Nevokshonoff said, while the 48 investment tax credit offers between 6% and 30% of the capital spend for hydrogen projects that produce hydrogen with a carbon intensity lower than 4.0 kgCO2e/kgH2. There’s also the 45Q carbon capture, utilization and storage tax credit, that offers carbon dioxide emitters $85 for every tonne of CO2 that is captured and sequestered.

However, ramping up the production of blue hydrogen in the U.S. will face some challenges, including managing opposing public sentiment toward carbon capture technologies and using fossil fuels to produce hydrogen, as well as determining appropriate use cases for hydrogen where other alternatives, like electrification, are not more appropriate, he said. 

“Securing long-term offtake contracts, which are essential to reaching final investment decision on projects,” will also be a challenge, Nevokshonoff said, as will ensuring the appropriate infrastructure to transport carbon dioxide and hydrogen. 

But some stakeholders remain skeptical of blue hydrogen. In September, the Institute for Energy Economics and Financial Analysis issued a report that concluded the U.S. government could be significantly understating the global warming impact of producing hydrogen from fossil fuels. The authors took a closer look at the carbon intensity of blue hydrogen – defined as being produced from natural gas or coal, both of which contain methane – and studied its potential methane emission rates, leakage, as well as the effectiveness of carbon capture technologies. It eventually determined that producing hydrogen from natural gas is not a low-carbon solution. 

Small-to-midsize industrial carbon emitters in the U.S. are clustered in several regions across the country, potentially allowing for the development of carbon capture, utilization and storage (CCUS) hubs, a new report from the EFI Foundation and Horizon Climate Group found. 

In total, there are more than 3,000 such carbon emitters in the country, collectively producing some 266 million metric tons of carbon dioxide every year – roughly a quarter of annual U.S. industrial carbon dioxide from point sources, according to the report.  

The report looked at carbon capture opportunities in 11 industrial subsectors, with over half of the emissions coming from emitters that are in the business of producing, transporting and processing petroleum and natural gas, as well as refining petroleum, and producing ethanol and petrochemicals. Natural gas use comprised nearly three-quarters of the total carbon dioxide emissions from these targets, the report said. 

Achieving American climate goals will require going beyond the power sector, and pursuing industrial decarbonization and carbon removal, Ernest Moniz, former U.S. Secretary of Energy and current CEO and president of EFI Foundation, said. 

“Carbon capture, utilization, and storage hubs are pathways to effective industrial decarbonization of small and midsize emitters,” Moniz said. 

CCUS technologies essentially capture and compress carbon emissions from power generators and other emitters, either to store underground or channel to alternate uses. Over the next three decades, large-scale carbon capture capacity could double every five years, IHS Markit reported in 2021. At the time, there were 23 such projects under construction, financing and design, estimated to double CCUS capacity by 2026.

Prior studies on carbon capture, utilization and storage have generally focused on relatively higher carbon emitters, but small-to-midsize industrial emitters collectively account for roughly a quarter of all industrial emissions. With the deployment of CCUS hubs, multiple such facilities can use the same transport and storage operations, allowing for lower costs on the whole.

The report identified 10 potential regional clusters of small-to-midsize industrial facilities that could allow for the creation of such a hub. Together, these 10 clusters comprise 1,000 facilities that produce 111 million metric tons of emissions every year.  

Four of these – representing 700 facilities, producing more than 70 million metric tons of carbon emissions every year – were then chosen for a more detailed study. These include southeastern Texas, around Houston; the Louisiana Gulf Coast; the eastern Ohio River Valley area; and the southern Great Lakes region. These four regions all have larger-scale carbon capture projects that are either planned, being developed or operational, which could be “anchor tenants” for a larger hub, the report said. 

While historically many U.S. industrial facilities were thought to be too difficult to decarbonize, the report “underscores that a cluster approach to carbon capture, particularly point-source carbon capture technology, is the most viable path forward for heavy industries,” said Aniruddha Sharma, CEO and chair of Carbon Clean, a carbon capture company and sponsor of the report. 

The report also laid out a series of recommendations to facilitate the build-out of these hubs. For instance, while recent changes to the Section 45Q tax credit are a step in the right direction, the incentive can be further tweaked to facilitate the transferability of the credit, or expand optional direct pay eligibility, the report said.

The Department of Energy could also take steps to leverage funding from the Bipartisan Infrastructure Law and Inflation Reduction Act to support the buildout of carbon capture hubs, the report noted – for instance, by expanding DOE loan guarantee authorities to allow the financing of multiple CCUS projects for certain industrial applications. 

Southern California utility San Diego Gas & Electric Company (SDG&E) and Toyota Motor North America are working together on researching vehicle-to-grid applications (V2G) for battery electric vehicles.

The research is specifically focused on bidirectional power flow, a technology that would allow EV owners to both draw power from the grid, as well as export it back to the power system from their car batteries. Electricity system stakeholders have been eyeing vehicle-to-grid – or V2G – technology for its ability to improve grid reliability and resilience, as well as help integrate renewables and potentially lower electricity costs. 

“V2G has the potential to be a game changer for the power grid and for consumers,” Miguel Romero, SDG&E’s chief commercial officer, said. 

SDG&E’s footprint is one of the largest markets for Toyota’s electric and plug-in hybrid electric vehicles, and California itself is one of the fastest-growing EV markets in the region. The utility has electrified over a fifth of its over-the-road fleet, and has deployed more than 3,600 chargers at offices, schools, parks and industrial facilities in its service territory.

The companies intend to conduct their research at SDG&E’s San Diego campus, and will use a bidirectional charger and vehicle-to-grid platform from Fermata Energy. Based on this research, SDG&E is aiming to get a better understanding of the infrastructure it will need to deploy to ensure the growth of vehicle charging infrastructure. Both companies also plan to pinpoint new products and services that can provide customer benefits. 

Vehicle-to-grid technology essentially allows EVs to operate as grid storage assets that provide the same services as stationary storage, but at a lower cost, David Slutzky, founder and chairman of Fermata Energy, told pv magazine USA. 

The size of EV storage capacity is massive, Slutzky added – California, for instance, anticipates having 8 million EVs on the road by 2030.  If every one of these EVs was paired with a 10 kW bidirectional charger, this would represent an 80 GW grid resource, he said. 

Toyota is looking to empower utilities to better anticipate and leverage the significant number of plug-in hybrid and electric vehicles on their grids, both as a growing source of energy demand and, in the future, energy supply, Christopher Yang, group vice president of Toyota EV Charging Solutions, said. 

“We are embracing the concept of an entire electrified ecosystem for our customers, and the ability for vehicles to integrate with the grid is an essential component of this ecosystem,” Yang said. 

Bidirectional charging technology has been installed across the country, but is still somewhat nascent, according to Slutzky. In thinking about policy support for this sector, parallels can be drawn between the technology and the birth of the rooftop solar industry, he said. There were three policy pillars that supported the growth of rooftop solar – interconnection, incentives, and compensation for excess solar generation, in the form of net energy metering.

“Similarly, bidirectional charging and V2G needs to be more easily approved for interconnection, gain access to incentives already available for stationary storage and unidirectional chargers, and become eligible for compensation for exports of power from EVs to the grid,” Slutzky said. 

Bidirectional charging technologies also require a fourth interoperability pillar, he added.

“Although efforts are underway to standardize communication and technical standards, the fully interoperable environment needed for V2G to scale will require a great deal of work,” Slutzky said.

Antora Energy received a grant for over $4 million from the California Energy Commission (CEC) and Department of Energy’s Advanced Research Projects Agency – Energy to scale up its heat-to-power thermophotovoltaic technology, which can store renewable power as heat in blocks of solid carbon, which converts stored heat into electricity.

The funding, which comes from the CEC’s Electric Program Investment Charge (EPIC) program and another program at the Department of Energy’s Advanced Research Projects Agency-Energy, represents “critical state-federal collaboration to scale innovative clean energy technologies,” the company said. 

The additional funding will further accelerate Antora Energy’s production of thermophotovoltaic technology, or TPV, Andrew Ponec, the company’s co-founder and CEO, said.

“With TPV, Antora is capable of decarbonizing the entire energy demand of large industrial facilities—both heat and power—opening the fastest, least expensive path for the industrial sector to reach net zero,” said Ponec. 

“Industrial emissions are among the hardest to abate and Antora’s cutting-edge technology holds promise in overcoming that challenge,” Jonah Steinbuck, R&D director at the CEC, said. 

The company’s thermophotovoltaic technology essentially converts heat to electricity with no moving parts, Brendan Kayes, its head of photovoltaics research and development, told pv magazine USA. 

“Much like a solar cell is designed to capture light from the sun, TPV cells convert the light emitted from glowing-hot objects—like Antora Energy’s carbon blocks—into electricity,” Kayes said. 

Antora Energy says its thermal batteries offer a cost-effective way to store energy and produce high-temperature industrial heat and electricity on demand. So far, processes that convert heat into electricity have historically required extensive machinery with lots of moving parts, Kayes said.

“Think steam turbines and internal combustion engines—technologies that have dominated for centuries—that require expensive, ongoing maintenance, and are only efficient and cost-effective at large scale,” Kayes said. 

Antora Energy’s thermophotovoltaic cells, however, are modular and manufacturable, so their efficiency and cost are independent of scale — enabling cost-effective deployments from kilowatts to gigawatts, Kayes added. This means it could help replace the use of fossil fuels in processes in the food and beverage, paper products, chemicals, steel and cement industries.

The company’s technology has met two thresholds around efficiency and manufacturing at scale, it says – it has demonstrated heat-to-electricity conversion efficiencies higher than 40%, and earlier this year, set up a dedicated manufacturing line for thermophotovoltaic cells that is the first of its kind in the world. The manufacturing line is located in Sunnyvale, California and has an initial capacity of 2 MW of cells per year. 

The thermal batteries are built to address energy needs across virtually every industrial sector, and could have major ramifications in sectors beyond manufacturing, including the electric grid, remote power and others, Kayes said. 

Last December, Antora Energy announced it had acquired Medley Thermal – a developer and software company specializing in renewable power-to-heat systems – to help commercialize its heat and power technology. Medley Thermal had previously developed projects that used renewables to cost-effectively electrify heat, and had a robust pipeline of power-to-heat projects, Antora Energy said. 

Long-duration energy storage (LDES) technologies, paired with renewables, could shrink global industrial greenhouse gas emissions by 65%, a new report from the LDES Council and Roland Berger has found. 

These technologies can be used to support firm, renewable electricity for off-grid applications, and can reduce the cost to decarbonize certain fossil fuel-powered industrial processes, according to the report. 

Long-duration energy storage is likely to be a key component of a highly-renewable grid, and the U.S. Department of Energy (DOE) estimates the country could need between 225 GW and 460 GW of the resource to achieve a net-zero economy by 2050. The agency categorizes the technologies into four segments – up to four hours of storage, or short duration; inter-day, which provides 10 to 36 hours of storage; multi-day, which can extend to 160 hours; and seasonal shifting, which exceeds that. The LDES Council represents 70 members across 19 countries, and is focused on the acceleration of long-duration energy storage. 

Long-duration electric and thermal storage technologies can be used to “firm” wind and solar for off-grid use, meaning renewable energy can be used to decarbonize certain industrial processes currently powered by fossil fuels, the report said. The technologies are already economically attractive to allow off-grid facilities to switch from diesel to this firmed renewable energy – even without carbon incentives, according to the report

The report acknowledged that currently, there is very little deployment of long-duration storage technologies in hard-to-electrify sectors, like steel and cement. This is due to integration requirements for electric technologies to support high temperature, radiative heat needs in these industries, the authors said. 

However, these technologies “can already reduce emissions in these sectors by enabling those industrial users to take advantage of intermittent renewable generation for their round-the-clock electricity needs, and accessing CO2-free heat supply and recovery waste heat for lower temperature processes,” according to the report. 

Industrial carbon emissions comprise around a quarter of annual global greenhouse gasses, and are growing by 2% every year. In fact, the demand for industrial heat is expected to grow by 34% between 2019 and 2040. 

However, allowing these technologies to reach their full potential will require a series of policy interventions, including technology support, long-term market signals and revenue mechanisms. The first category could include things like grants and incentives, while the second would include things like carbon pricing, procurement targets for long-duration storage and phasing out fossil fuel subsidies, the report said.

And then once you have long-duration resources on the grid, or they’re going to be on the grid imminently, the question is “how do you make sure that they’re compensated, and how do you make sure that the value that they bring to the grid is recognized?” said Gabe Murtaugh, director of markets and technology with the council. 

These could include measures like long-term bilateral contracts for balancing or ancillary services, or building out capacity markets, according to the report.

“Obviously this is a very high-level list – the devil tends to be in the details on some of these, and there are a lot of efforts the LDES Council is working on…” said Murtaugh. 

Grid solutions providers Swell Energy and Shifted Energy are merging the capabilities of their individual distributed energy resource management systems into a single offering that they say will help utilities better manage distributed assets on the grid. 

Shifted Energy’s Grid Maestro system focuses on the smart management of household loads, like water heaters, thermostats and electric vehicle chargers, while Swell’s GridAmp manages and dispatches distributed solar and energy storage systems. Together, the two comprise a turnkey virtual power plant (VPP) solution that will provide utilities with forecasts of energy demand and generation across the board, the companies say. 

As the electricity grid grows more distributed, VPPs – essentially networks of distributed energy resources, like rooftop solar and home battery storage systems – are becoming a key solution to ensuring reliability amid a transitioning energy mix and extreme weather events. 

VPPs can improve the way electricity supply and demand are balanced on the grid – a balancing act that is becoming more crucial as the grid relies increasingly on renewable energy sources like solar and wind, which don’t produce electricity as steadily as a traditional fossil fuel plant, Sarah Delisle, vice president of government affairs and communications at Swell Energy, told pv magazine USA.

“By spreading out smaller, localized energy generation systems across the grid rather than depending on a few large, centralized power plants, we can reduce our dependence on long-distance power transmission,” she said. 

And the integration of the two companies’ platforms offers several benefits to utilities, Delisle said. By expanding the pool of distributed energy resources (DERs) available to participate in a VPP, utilities can access a larger pool of controlled energy capacity in a single program, for example. And with more DERs integrated into the grid, they can use demand response strategies to reduce load during peak times, for instance by instructing connected devices to lower their energy use. 

There’s also the potential to use these resources for “capacity building” events – for instance, during times of low demand on the grid, excess energy from solar panels or the grid can be stored in batteries or water heaters, and then used during peak hours, she said. 

“A grid with greater control of and participation from the distributed energy generation and loads it is designed to serve can better withstand disruptions and provide improved grid resilience,” said Delisle. 

Moreover, utilities can also see cost savings by deferring or avoiding infrastructure upgrades that would otherwise be needed to meet peak demand, she added. 

The companies are working with multiple utilities in California and Hawaii, but in light of the changing climate, aging infrastructure and increasing demand on the grid, see VPPs as a good fit almost everywhere. That said, certain states – including Arizona, Florida, Idaho, Maryland and Massachusetts, among others – have markets and economics that are most advantageous for the technology, Delisle said. These states are also where Swell and Shifted are focusing their efforts. 

A Brattle report from earlier this year compared the net cost of providing 400 MW of resource adequacy from three resources – a natural gas peaker, a grid-interconnected battery system, and a VPP composed of residential demand flexibility technologies – and found that the VPP offered utilities a net cost that is roughly 40% to 60% that of alternative options. In fact, 60 GW of VPP deployment could meet future domestic resource adequacy needs at a cost that is $15 billion to $35 billion lower than alternatives over the ensuing decade, according to the report. 

Renewables and energy storage company Agilitas Energy has constructed a 4.8 MW/23.7 MWh standalone, non-wires solution energy storage project in Con Edison’s service territory. 

The lithium-ion battery project is located in Long Island City, Queens, and is meant to help the utility meet peak loads in its footprint. Agilitas has entered into a ten-year contract with Con Edison to discharge as much as four hours of stored energy during its peak demand period, running from May 1 through September 30. During this time, the utility can request power daily with some advance notice. 

The energy storage project is expected to come online in 2024. It will boost Con Edison’s grid reliability and resiliency, according to Agilitas. The company says the batteries can charge during off-peak hours, when the grid is less strained and electricity is priced lower, and then discharge to customers when power demand increases.

In addition, the project will participate in New York’s Value of Distributed Energy Resources value stack tariff, Zac Osgood, vice president, EPC, Agilitas Energy, told pv magazine USA. The value stack is a mechanism that compensates distributed energy projects as they provide electricity back to the grid. 

The Long Island project provides Con Edison and local ratepayers with a more cost-effective solution to providing critical, dispatchable demand relief to support ongoing load growth in the area, Osgood said. 

Along with other non-wires projects in the area, it will help alleviate deficiencies identified in the existing local electrical infrastructure – meaning it will help support that load growth without having to perform costly upgrades and substation transformer replacements that would have otherwise been required, Osgood added. 

Last year, New York Gov. Kathy Hochul unveiled a plan for the state to hit 6 GW of energy storage by 2030 – roughly 20% of its peak electricity load. The roadmap would include storage deployments estimated to reduce future electric system costs in New York by nearly $2 billion. 

More broadly, energy storage has a key role to play in ensuring reliability as the share of renewables on the grid continues to grow. In addition to discharging power when demand is high and the grid is under stress, energy storage can also serve as an aide during extreme weather events, Osgood said, acting as a back-up power source during outages and ensuring power is delivered at critical times of peak demand. 

“Energy storage has emerged as essential for keeping the grid running during extreme weather events, following our recent summer of record-breaking heat and power demand,” he said. 

New York City is arguably the most complicated and challenging urban area to build an energy storage project with its  regulatory hurdles and zoning restrictions, Barrett Bilotta, president, CEO and co-founder of Agilitas Energy, said.

“This energy storage system will serve as a huge win for consumers as our project will enhance reliability, support the transition to a clean energy future and help defer the costs of building more infrastructure,” Bilotta added. 

Last June, Agilitas Energy announced it had raised $350 million of equity from funds managed by CarVal Investors L.P, expected to support the company’s project pipeline of more than 500 MW. 

Electriq Power Holdings, a provider of energy storage and management solutions, has launched a program in the city of Derby, Connecticut to help homeowners access solar-plus-battery solutions regardless of their socioeconomic status.

The program, dubbed PoweredUp Derby, is supported by the city and will contribute to lowering electricity costs and providing back-up power for participants during outages, according to the company. Under the program, homeowners can have a turnkey solar-plus-battery storage system installed in their homes without any upfront costs, income verification, credit score, or property lien requirements. Almost 3,000 homeowners in the city are eligible for the program.

“It gives customers, including those who are low-to-moderate income the ability to access clean, reliable energy whereas traditionally, to install a system like this, you’d have to pay upfront,” CEO Frank Magnotti told pv magazine USA. 

These systems are also compatible with virtual power plant programs and if needed, can be integrated with local programs, he added. 

Electriq Power calls these set-ups ‘Sustainable Community Networks’ (SCNs) and has deployed a number of them in California. This will be its first SCN in the New England region. Both these areas have very high electricity costs – in Connecticut, for example, the retail price of electricity is around 10 cents/kWh higher than the national average, and has risen 17% between 2015 and 2022 – which is one of the reasons the company has targeted them. 

That’s because solar-plus-battery storage systems can help homeowners save money – in part by storing demand when energy is cheap and plentiful, and then discharging it during peak demand periods, when electricity rates are high. Electriq Power estimates that the systems can help save up to 20% in electricity costs annually. 

Electriq Power’s partnership with the city of Derby will help residents lower electricity costs and strengthen their financial position, Roger Salway, the city’s economic director, agreed.

“This is a program that can help residents improve their life, and for us, that’s a win-win,” Salway added. 

Electriq Power is also actively pursuing additional SCN programs throughout New England, and “would welcome the opportunity to work with municipalities and community-based organizations within the area to help them accelerate their sustainability goals, while assisting residents with lowering their electricity bills and being prepared for power outages,” Magnotti said. 

In addition to being a source of back-up power, Electriq Power’s solar-plus-storage systems also have the ability to export power back to the grid. The battery storage component of the system is equipped with operational software that allows owners to participate in virtual power plant programs, Magnotti said, where their stored energy can be exported to the local electrical grid to help alleviate stress when demand is high, helping to prevent a power outage.

In March this year, Electriq Power entered into a multi-year agreement with a U.S.-based clean-energy company for financing estimated to be more than $300 million over 30 months. This funding was reportedly to support the deployment of SCNs in California, which Electriq Power views as a hedge against rising utility rates. 

Distributed generation platform Aspen Power has constructed 14 solar projects, amounting to 49.4 MW generation capacity, acquired from Inman Solar in Georgia.

The projects were originated and developed by Inman Solar, a contractor that specializes in utility and large commercial solar farms, and Aspen Power will now serve as their long-term owner and operator. They consist of ground-mounted solar panels with single axis trackers. Aspen Power will now serve as the long-term owner and operator of the projects and with this acquisition, the company has 43 projects in the state, amounting to 140 MW of capacity. 

“The Inman team has done a fantastic job bringing high quality projects to the table, and we’re glad to have worked with their team to get these projects across the finish line and to become the long-term owners and operators,” said Lara Bushwood, director of project development with Aspen Power. 

The projects are currently online and generating clean electrons, Dan Gulick, senior vice president of community solar at Aspen Power, told pv magazine USA. 

The systems have been contracted through long-term power purchase agreements to provide energy to Georgia Power, an Atlanta, Georgia-based electric utility and subsidiary of Southern Company. The contracts are a result of a request-for-proposals for distributed generation that the utility issued in 2020. 

Like many parts of the country, Georgia’s electric grid is in the midst of a transition. Back in 2019, the Georgia Public Service Commission required Georgia Power to procure 2.21 GW of solar over the next half decade – up from the utility’s earlier plans to procure 1 GW – in four tranches of distributed and utility-scale solar, expected to approximately double the volume of solar in the state. 

In mid-2022, Georgia utility regulators approved an integrated resource plan – essentially, a long-term road map – filed by Georgia Power, which calls for retiring and decertifying all but two of the utility’s coal-burning facilities, and replacing them with a planned 2.3 GW of renewable energy. The plan also included some 500 MW of battery energy storage. 

However, solar developers across the country still face challenges related to interconnection delays, costs and sometimes, local permitting, Gulick said.

Given this, policy makers need to continue to have dialogue with the industry, he added, pointing to places like New Jersey and Maryland, where more community solar markets have opened up. 

“For Aspen Power’s customers, this means we can have simpler agreements, create more value and provide solar to anyone who’s interested,” Gulick said. 

Another role that policy makers could play concerns finding a balanced approach for allocating interconnection upgrade costs, he said – in most situations, the solar project bears all the costs for upgrading the distribution circuit and substation. This ignores the public benefit these upgrades provide, Gulick said.

“The counterargument is that the utility should be allowed to rate-base these costs as it avoids some of the upgrades that will be required as we increase the electrification of the economy,” like electric vehicles and heat pumps, he said. 

Green hydrogen solutions provider H2B2 Electrolysis Technologies is working on the largest operational green hydrogen production plant to date in North America, which will be powered entirely by renewable energy.

The project – called SoHyCal – is located in Fresno, California, and is currently fully operational in its first phase, in which it is producing up to one ton of hydrogen per day using biogas and electrolysis technology. 

In its second phase, it will transition to also using solar energy from a nearby photovoltaic plant, and is expected to scale up to producing up to three tons of hydrogen per day – enough to power 210,000 cars or 30,000 city buses every year. It will also continue using biogas to produce hydrogen in this phase. The facility is expected to get to this point by the second quarter of 2024. 

Both the biogas and solar energy sources are adjacent to the site, and directly connected to it, Pedro Pajares, CEO of H2B2 USA, told pv magazine USA. SoHyCal is a behind-the-meter facility.

In May, H2B2 announced that it had entered into an agreement with RMG Acquisition Corp. III,  a special purpose acquisition company, to take the former public. H2B2 was founded in 2016, and while most of its presence is in the U.S. and Europe, it is also expanding in the Latin America and Asia-Pacific regions. 

The green hydrogen market is viewed as having significant potential, according to the company, and forecasts indicate it could reach a value of $10 trillion by the end of the decade. The industry’s growth will come from various sectors, including industrial use, transportation, and power generation, the company said. 

However, one of the challenges the industry faces is the correct development of infrastructure and financial models to support the hydrogen ecosystem, Pajares said. 

In terms of how policymakers could address these challenges, Pajares said they “are taking the right steps to develop both the market and the ecosystem. If any, I would add the legislative needs to keep listening to the private sector as a whole, from producers to consumers to infrastructure and supply chain.”

The Fresno facility has also received regulatory support, including in the form of a $3.96 million grant from the California Energy Commission’s clean transportation program. That funding has been key to getting the plant to its 1 ton-per-day of hydrogen production capacity, and the fuel is being used at hydrogen refueling stations in the San Joaquin Valley and the San Francisco Bay Area.

California regulators have also been providing funding to other players in the hydrogen market. In August, heavy-duty battery and fuel cell vehicle manufacturer Nikola announced it had received $58.2 million in grants from various regulatory agencies – including $41.9 million from the California Transportation Commission and $3.3 million from the California Energy Commission – to build a network of hydrogen refueling stations for heavy-duty trucks. 

Duke Energy is set to break ground on the country’s first demonstration project with an end-to-end system to produce, store and combust entirely green hydrogen.

The facility will be located at the utility’s DeBary solar plant in Volusia County, Florida, which currently has a 74.5 MW capacity.

Once completed, the clean energy from this facility will be routed to two 1 MW electrolyzer systems, which will split water into oxygen and green hydrogen. The hydrogen will then be transferred to reinforced containers, where it will be stored until needed. When electricity demand is especially high, the green hydrogen will be passed through a combustion turbine to convert it into power. 

The combustion turbine will be upgraded with technology from GE Vernova to run on either a blend of natural gas and hydrogen, or up to 100% hydrogen – the first turbine in the country that can get to such a high hydrogen percentage. The demonstration project will begin construction later this year and is expected to be fully operational sometime in 2024. 

Green hydrogen can play a key role in ensuring the reliability of a highly-renewable electric grid, since it serves as a “dispatchable” energy source that is available on demand. Unlike solar and wind power, it is not dependent on the time of day or weather. Moreover, using solar energy to create green hydrogen can optimize the solar plants, according to Duke Energy. 

“Relying on intermittent energy sources without available dispatchable energy sources would put our future electric system at risk of having insufficient energy to serve customer demand,” the utility said. 

Duke Energy is aiming to reduce its carbon emissions from electricity generation by 50% by 2030, and achieve net-zero emissions by the middle of the century. As part of this, it is looking to decrease its use of coal to less than 5% of total generation by 2030, and phase out the fossil fuel entirely by 2035. 

The utility anticipates that hydrogen could play a major role in its clean energy future, said Regis Repko, Duke Energy’s senior vice president of generation and transmission strategy.

“Hydrogen has significant potential for decarbonization across all sectors of the U.S. economy. It is a clean energy also capable of long-duration storage, which would help Duke Energy ensure grid reliability as we continue adding more renewable energy sources to our system,” Repko said. 

While adding hydrogen facilities can help optimize solar plants, some industry players say that driving down solar’s levelized cost of energy – below $20 a megawatt hour – can also spur the adoption of solar for green hydrogen production. 

In fact, producing green hydrogen itself can be profitable in “wide swaths of the U.S.,” a report from policy consultancy Energy Innovation found – regions where the cost of electricity from new wind and solar averages less than $25 per MWh. And as the capital costs of electrolyzers decline, green hydrogen projects are likely to become economic in more areas. 

Vortex Energy Corp, a company focused on acquiring, exploring and developing mineral properties in North America, is partnering with the University of Alberta on research into hydrogen and energy storage at its Robinsons River Salt Project.

The company has committed $300,000 to a research team at the university that is working on designing and implementing the first field trial of hydrogen storage of domal salt in Canada. The partnership is expected to run for two years. 

While hydrogen is a clean and useful energy source, it is complex to store because it is light and can easily escape, Paul Sparkes, CEO of Vortex Energy, told pv magazine USA.

“This is where salt caverns come in. These are natural underground formations created by salt deposits. Scientists have found that these caverns are able to hold on to hydrogen gas for a prolonged period of time,” Sparkes added.

Caverns can be created in salt domes by drilling into them and injecting the rock with water, which dissolves the salt, and the resulting brine is extracted, leaving a large cavity, Sparkes said. Hydrogen electrolyzers can convert water into hydrogen by using renewable energy and this can be stored, and reconverted to electricity when needed over long periods of time, making it more suitable for seasonal or long-term storage needs, Sparkes added. 

Vortex Energy is working on its Robinson River Salt project, which has two of the largest salt caverns discovered in Atlantic Canada that have the potential to be developed for hydrogen or energy storage, Sparkes said. The two salt structures are estimated to hold at least 800,000 tonnes of hydrogen within more than 60 caverns, according to the company. The company plans to begin drilling at the project this November, after which it will re-evaluate further development and field trial application. Pending funding, Vortex Energy hopes to advance toward cavern storage in approximately two to three years, Sparkes said. 

The University of Alberta research time will conduct proof of concept experiments on core samples, to design and implement the first field trial of hydrogen storage in domal salt in Canada, according to Sparkes. The project is expected to last two years, comprising four research phases: optimizing the depth interval of the proposed storage caverns; evaluating the possibility and extent of hydrogen loss through the proposed cavern wall; evaluating the extent of hydrogen contamination; and evaluating the mechanical stability of the proposed caverns, Jason Latkowcer, in corporate development with Vortex, told pv magazine USA. 

Clean hydrogen could play an important role in decarbonizing hard-to-abate industries. But the more we rely on the resource, the more we’re going to need storage to preserve it, Latkowcer said. 

“The potential market for hydrogen storage in salt caverns is substantial. Green hydrogen storage in salt caverns has a number of advantages, including an indispensable chain link, flexibility, safety, and small footprint,” he said.

The U.S. Department of Energy (DOE) has announced $7 billion to kick off seven regional clean hydrogen hubs in the U.S., with the broader aim of supporting the commercial-scale deployment of clean hydrogen in the country. 

The seven hubs are funded by the Bipartisan Infrastructure Law, passed in 2021, and will, according to the DOE “kickstart a national network of clean hydrogen producers, consumers, and connective infrastructure while supporting the production, storage, delivery, and end-use of clean hydrogen.” They are collectively expected to produce three million metric tons of hydrogen each year, and reduce around 25 million metric tons of carbon dioxide emissions annually. 

Projects that were selected for negotiation include the Appalachian Hydrogen Hub, California Hydrogen Hub, Gulf Coast Hydrogen Hub, Heartland Hydrogen Hub, Mid-Atlantic Hydrogen Hub, Midwest Hydrogen Hub and the Pacific Northwest Hydrogen Hub. However, these selections don’t represent a commitment of funding from the DOE; the agency will now go through a negotiations process with the applicants. The H2Hubs program is managed by the DOE’s Office of Clean Energy Demonstrations.  

“Unlocking the full potential of hydrogen—a versatile fuel that can be made from almost any energy resource in virtually every part of the country—is crucial to achieving President Biden’s goal of American industry powered by American clean energy, ensuring less volatility and more affordable energy options for American families and businesses,” said Jennifer Granholm, U.S. Secretary of Energy.   

Clean hydrogen has emerged as an important priority for the Biden-Harris Administration, in part due to its potential in industries that would otherwise be hard to decarbonize, including heavy-duty transportation. The administration is looking at domestically producing 10 million metric tonnes (MMT) of clean hydrogen annually by 2030, ramping up to 20 MMT annually by 2040 and 50 MMT annually by 2050. 

The DOE’s announcement is a critical first step in decarbonizing existing carbon-intensive hydrogen applications such as ammonia production for fertilizers and petrochemicals refining and in decarbonizing new applications of hydrogen in hard-to-abate sectors, including heavy-duty trucking, shipping, and aviation, said Anna Menke, senior hydrogen hubs manager at the Clean Air Task Force. 

It is also a “major step forward for the hydrogen economy here in the United States,” said Frank Wolak, president and CEO of the Fuel Cell and Hydrogen Energy Association.

“Engagement by state and local leaders in communities across the country, matched with significant private investment, will develop the hydrogen economy so consumers, businesses and communities can decarbonize many of the most difficult heavy-using energy sectors like heavy-duty and long-haul transportation, cement, aluminum and steel, all-the-while providing important, good-paying clean energy jobs,” Wolak added. 

However, some stakeholders remain skeptical. 

“Throwing billions at hydrogen hubs deepens our dependence on fossil fuels and worsens the climate emergency,” said Maggie Coulter, an attorney at the Center for Biological Diversity’s Climate Law Institute. 

“President Biden should be urgently investing in proven and increasingly affordable solar and wind energy. It’s wasteful and misguided to fund false solutions like hydrogen that only further burden frontline communities,” Coulter added. 

Lithium-ion battery recycler Aqua Metals and 6K Energy plan to create the first “truly sustainable circular supply chain” for domestic lithium-ion battery manufacturing in the U.S.

The two companies have signed a multi-part memorandum of understanding, and are planning a co-located facility at a site in Jackson, Tennessee. This facility will be the first of its kind, producing low-carbon cathode active materials for batteries, using raw materials from domestically-sourced batteries that are at the end of their life, as well as scrap materials from manufacturing partners. 

The company expects to construct the co-located facility starting in 2026, as 6K Energy ramps up their cathode manufacturing operations and demand for critical battery metals, Steve Cotton, president and CEO of Aqua Metals told pv magazine USA.  

“In the interim, we are building out our first commercial scale recycling campus in Tahoe-Reno, capable of processing 10,000 tonnes per year of battery material when at full capacity, and this facility will supply recycled materials for low-carbon cathode active material (CAM) manufacturing,” Cotton added. 

At the shared facility, Aqua Metals will transform spent batteries and manufacturing scraps into raw materials for 6K Energy’s proprietary cathode active materials manufacturing process. The former’s technology is based on using electricity to recover critical materials from end-of-life lithium-ion batteries, a process it estimates will reduce landfill waste from current battery recycling processes by 95%. 

The companies’ partnership will foster domestic job growth, technological advancement, and a sustainable footprint in the global lithium battery market, building a robust supply chain for the technologies critical to combating climate change at a lower cost than China, said Sam Trinch, group president at 6K Energy. 

The American lithium battery recycling industry is just getting started, and Aqua Metals is one of only two operational lithium battery recyclers today. But this model of meeting the growing demand for low-carbon battery materials with a modular recycling technology is highly replicable and can be scaled to fit other battery manufacturing plants, according to Cotton. There are many benefits to co-locating recycling operations right alongside other facilities in the battery supply chain, he added. 

“One of the main sources of material for recycling in the coming decade will be manufacturing scraps and out of spec batteries – and eliminating the distance these materials travel is a significant cost and emissions savings,” he said. Integrated facilities like these also offer operational efficiencies, lowering production costs and reducing carbon emissions even further, Cotton said. 

In September, battery supplier Dragonfly Energy announced it had manufactured a lithium-based battery cell using lithium hydroxide pulled by Aqua Metals from recycled batteries. The lithium hydroxide was recovered from a mixture of crushed and shredded battery cells – called “black mass” – which contains valuable raw materials, including lithium. The two companies are working on clothing the “lithium loop” in Nevada, a state that is believed to have the largest source of lithium in North America, as well as a quickly growing market for electric vehicles and energy storage systems. 

Electrolyzer manufacturer Electric Hydrogen has completed an oversubscribed $380 million Series C financing, bringing the company new capital to ramp up the manufacturing and deployment of green hydrogen systems.

The funding round was led by several companies, including Fortescue, Fifth Wall and Energy Impact Partners, and also included new investors like bp Ventures and Oman Investment Authority.

The company manufactures 100 MW electrolyzer systems, each of which it says can produce almost 50 tons of green hydrogen each day, at low costs. In total, it has raised more than $600 million since it was founded three years ago. 

Hydrogen produced from clean sources could play a key role in decarbonizing the U.S., especially when it comes to “hard-to-decarbonize” sectors – for instance, heavy transportation, as well as industrial and chemical processes. 

It has also emerged as a key priority for the Biden-Harris Administration. In June, the administration issued a national clean hydrogen strategy and roadmap, charting a pathway to domestically produce 10 million metric tonnes (MMT) of clean hydrogen annually by the end of the decade, 20 MMT annually by 2040, and 50 MMT annually by 2050. In addition, the administration plans to invest $8 billion in building regional hydrogen hubs.

This August, the administration also launched an inter-agency task force to create a  “whole of government” approach to clean hydrogen. The task force will be co-chaired by Mary Frances Repko, White House deputy national climate advisor and David Turk, deputy secretary of the U.S. Department of Energy (DOE). 

Some experts feel that the key to building out a green hydrogen economy is driving down the cost of solar electricity to produce that hydrogen. 

Electric Hydrogen’s electrolyzer technology is more efficient and lower cost, said Dave Eaglesham, the company’s chief technology officer.

“Now we’re scaling up rapidly to produce and assemble large electrolyzer systems for our industrial customers who are leading the shift from grey hydrogen to renewable green hydrogen,” he said. 

Electric Hydrogen is in the process of setting up manufacturing equipment in a 1.2 GW facility in Devens, Massachusetts. The factory is slated to begin manufacturing commercial electrolyzer systems early next year, and deliver them later in 2024. These deliveries include a system that will be installed at a New Fortress Energy green hydrogen project in Texas, which is scheduled to begin producing hydrogen in the fourth quarter of 2024, and reach full commercial operation in 2025. 

One of Electric Hydrogen’s lead investors and possible customers is Fortescue, a global metals and green energy company. 

“Fortescue is committed and focused on supporting the creation of green technology to help heavy industry decarbonize and producing green hydrogen at scale globally is integral to that,” said Mark Hutchinson, Fortescue Energy CEO. 

Clean chemistry company Mattiq is working on developing a portfolio of alternatives to iridium – a rare, costly material used in clean hydrogen production – in what the company calls the most comprehensive, systematic study of iridium alternatives ever conducted. 

Iridium oxide catalysts are used in proton exchange membrane water electrolyzers, a product that is being manufactured at larger scales in part to support the hydrogen industry. However, iridium is rare to find and very expensive — the current production of the material will only be enough for annual manufacturing capacity of around 3 GW to 7.5 GW of electrolyzers, according to the International Renewable Energy Agency. In contrast, forecasts indicate demand for 100 GW by the end of the decade. 

“Deploying alternatives to iridium oxide is essential to support this rapid growth, reducing supply chain risk and accelerating the scaling of clean hydrogen, an essential enabler in the effort to decarbonize hard-to-abate industrial sectors,” the company said. 

The company has to keep the specific alternative materials confidential to protect its intellectual property, but in general, the alternative catalysts are mixtures of metals that, by virtue of “alloying,” take on new properties compared to individual metals, Mattiq CEO Jeff Erhardt told pv magazine USA.

“As a result, we reduce or eliminate iridium content while retaining the performance of state-of-the-art iridium-based catalysts,” Erhardt said. 

The company expects to announce a commercial partnership within the first half of 2024. Mattiq is also in discussions with a number of industrial partners to commercialize and rapidly scale these products to market, and has seen a lot of interest so far, Erhardt said. 

However, the industry still faces some challenges in terms of ramping up the deployment of these iridium alternatives. One key challenge is the standardization of reliability testing for electrocatalyst materials, Erhardt said. 

The reason iridium catalysts are state-of-the-art is because they are durable and reliable over long periods of times in electrolyzers, and electrolyzer OEMs who want to integrate novel iridium alternatives into their equipment will first need to evaluate them under standardized testing conditions against the state-of-the-art catalysts they use now, he added. 

There are certain measures policy makers can take to help address these challenges. For instance, they could support third-party testing facilities, like national laboratories, that validate the performance of novel catalyst materials using best-practice protocols accepted by industry, Erhardt said. They could also continue supporting novel technologies across the development chain. 

Most importantly, he said, while hydrogen is currently garnering a lot of attention, policy-makers need to understand that electrolyzers and electrochemistry can do much more than produce hydrogen.

“We are working to enable the clean production of a vast range of chemicals, plastics, and fuels beyond hydrogen – and do so in a clean way. This is what will enable us to decarbonize the “hard-to-abate” chemicals industry,” said Erhardt. 

Battery supplier Dragonfly Energy has manufactured a lithium-based battery cell using high-purity lithium hydroxide that was recovered from recycled batteries – a proof of concept that could help build a more sustainable, circular battery manufacturing industry, the companies say. 

The lithium hydroxide was recovered by Aqua Metals, which is working on recycling solutions for materials used in energy storage and electric vehicle supply chains. The two companies are working on creating a closed lithium loop – where lithium batteries are sourced, manufactured and recycled – all in Nevada. 

Using recycled lithium addresses two major initiatives for Dragonfly Energy, its CEO Denis Phares said – “it helps close the loop by filling in that all-important recycling component, and it provides a ready and sustainable supply of lithium for use in upcoming cell production.”

“This is an exciting step forward for the emerging lithium battery industry, as we have qualified the high-purity lithium hydroxide Aqua Metals recovers from recycled lithium batteries to manufacture new battery cells,” Vick Singh, director of research and development at Dragonfly Energy, said.

The development is also an exciting milestone for Aqua Metals in establishing the efficacy of its sustainable recycling process, Steve Cotton, the company’s president and CEO, said.

The Reno, Nevada-based Aqua Metals pulled the lithium hydroxide from “black mass” – a term that refers to a mixture of crushed and shredded battery cells that have already been used, which contains lithium and one valuable raw materials. Dragonfly Energy used this lithium hydroxide to produce a battery cell with a patented dry powder coating process.

Both companies are eyeing the potential of building a closed lithium loop in Nevada, a state they believe is well-positioned to be “the starting and ending point for lithium batteries.” Nevada is believed to have the largest source of lithium in North America, according to the companies, and is also an expanding market for electric vehicles and energy storage technology applications.

Recycling is essential to creating a robust and sustainable energy storage industry in the U.S. and ensuring the country remains globally competitive in the clean energy sector, Aqua Metals’ Cotton told pv magazine USA.

“Recycling lithium ion batteries is the most immediate route to developing domestic supplies of critical minerals like lithium, cobalt and nickel, which are facing increasing supply shortages as the world ramps up clean energy manufacturing,” Cotton said.

The biggest challenge to closing the lithium loop in Nevada as well as other parts of the country will be timing, Cotton said. It is expected that the U.S. will have nearly a terawatt hour of lithium battery manufacturing operational by 2030, enough for 12 million to 13 million electric vehicles a year, he said.

“What we won’t have by then is the mines, mineral processing, and refinement capacity to satisfy the raw resource demand,” Cotton said.

Mines can take seven to 10 years to come online and begin producing battery-grade materials, while recycling facilities – which can be operationalized in six months – are constrained by the availability of recyclable materials, he added.

“Making the timing work out for resource demand, manufacturing, and our decarbonization ambitions will be a significant challenge as we create the closed loop systems necessary for a robust electrified economy,” Cotton said.

Water electrolysis technology company Verdagy is planning to open a new facility in Newark, California, which will be the first in the U.S. to manufacture advanced water electrolyzers in large volumes.

The facility will have more than 100,000 square feet of advanced manufacturing space, and the company plans to double its employees by next summer to manage the expansion and operation of the new plant. The facility is expected to come into operation in the first quarter of 2024. 

Verdagy caters to customers in heavy industries, like chemicals, ammonia and fertilizer, and steel; sectors that green hydrogen can play a key role in decarbonizing. The company says it is focusing on advanced manufacturing, cost reductions and product innovation that puts it on the pathway to the U.S. Department of Energy’s goal of hitting $2/kg levelized cost of hydrogen by 2026.

The U.S. needs to accelerate domestic production of electrolyzers as most of the production is outsourced from overseas manufacturers, Verdagy CEO Marty Neese told pv magazine USA. 

“If we enable domestic manufacturing of electrolyzers, it will also accelerate innovation that will have cascading effects on the overall cost and production capacity, enabling domestic manufacturing to become global leaders in the hydrogen industry,” Neese added. 

The new Silicon Valley manufacturing facility will accelerate the production and cost reduction of its 20 MW electrolyzer module, which is the basic building block for delivering larger, gigawatt-scale plants, according to Neese. 

Verdagy’s plans to expand its manufacturing capacity in California is set against the broader backdrop of the state’s hydrogen ambitions. California is focused on building an entire renewable hydrogen ecosystem to achieve its climate goasl, and that includes manufacturing electrolyzers, Dee Dee Myers, senior advisor to California Gov. Gavin Newsom, and director of the Governor’s Office of Business and Economic Development, said.

“Verdagy’s decision to expand their footprint here reflects California’s unique strength in creating new markets, enabling the creation of clean energy jobs while solving our most existential challenges with the technology of the future,” Myers said. 

One of the key challenges to ramping up domestic electrolyzer manufacturing capacity is access to capital to build out the needed infrastructure, Neese said. Policy-makers are already looking at ways to address these challenges. The DOE, as part of the Bipartisan Infrastructure Law, is encouraging companies like Verdagy to expand the U.S. supply chain for green hydrogen electrolyzer manufacturing, Neese added. 

In August, Governor Newsom instructed his Office of Business and Economic Development to develop a hydrogen market development strategy for California, which is expected to mirror the state’s zero-emission vehicle market development strategy. Clean hydrogen is likely to be a key component of achieving California’s climate goals, and the state is competing to be a federally-funded hydrogen hub under an $8 billion program that stems from the Bipartisan Infrastructure Law.

The new strategy will focus on using hydrogen to deploy clean energy and decarbonize the transportation and industrial sectors, and will be developed with input from agencies like the California Air Resources Board, the California Energy Commission, and the California Public Utilities Commission.

The U.S. government could be significantly understating the global warming impact of producing hydrogen from fossil fuels, according to a new report from the Institute for Energy Economics and Financial Analysis (IEEFA).

The report takes a closer look at blue hydrogen – which can be produced from natural gas or coal, both of which contain methane – and its authors analyzed the carbon intensity of the fuel, looking at potential methane emission rates, leakage, as well as the effectiveness of carbon capture technologies. 

“The findings in the current report are clear – producing hydrogen from natural gas is not clean, not low-carbon, and cannot and should not be considered a solution in our efforts to solve the world’s worsening climate change crisis,” said David Schlissel, director of resource planning analysis at IEEFA  and co-author of the report.

The 2021 Bipartisan Infrastructure Law and the 2022 Inflation Reduction Act have promised billions of dollars to establish hydrogen hubs around the country, and give production tax credits to the production of hydrogen as well as carbon capture and sequestration, Schlissel said. 

“We decided it was important to look at whether in fact blue hydrogen is clean and if not, in what circumstances it would not be clean,” he added. 

This report is the first in a series that the organization is planning, which will include analyses of producing hydrogen from coal and renewable natural gas, Schlissel said. 

IEEFA’s report points to four ways it says the U.S. government is significantly understating the global warming impact of producing hydrogen from fossil fuels. First is the assumption that just 1% of the methane used to produce hydrogen will be emitted into the atmosphere between the well and production facility, which the authors say is far less than recent scientific analyses have indicated.

Second is the focus on the 100-year global warming potential of methane, which is actually much lower than its 20-year global warming potential, according to the report.

Methane has a very high 20-year global warming potential, which declines over time, Schlissel said. 

“If you only focus on the 100-year figures… the impacts of methane in hydrogen are significantly smaller and that leads to an undercounting of their impact on global warming in the short term,” he said. 

The third factor is that the government assumes hydrogen does not have any effect on climate change when it leaks into the atmosphere, according to the report. 

And the fourth is the reliance on “overly optimistic and unproven assumption that hydrogen production projects will be able to capture almost all of the carbon dioxide they create.” 

In the case of hydrogen, the DOE has mandated a well-to-gate lifecycle analysis of emissions, which for blue hydrogen includes upstream emissions related to the production and delivery of natural gas, as well as emissions related to the electricity generation for hydrogen production and carbon dioxide management, Anika Juhn, IEEFA analyst and co-author of the report, said.

However, except for some of the emissions related to the transport and storage of captured carbon dioxide, the life cycle analysis covers emissions only up to the back gate of the production facility, she said.

“As a result, the downstream emissions related to hydrogen are not included,” said Juhn. 

According to the report, if more conservative assumptions are used for carbon capture rates, downstream hydrogen leakage, and downstream carbon emissions from the production of electricity needed to compress, store and transport the hydrogen, “then blue hydrogen gets even dirtier, with a carbon intensity more than three times as much as the DOE’s clean hydrogen standard.”

New research from the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) and Colorado State University (CSU) indicates that consumers could develop more confidence in switching to hydrogen-fueled vehicles if fueling station operators use predictive models that help them better plan for maintenance needs. 

According to the research, one of the key issues consumers of fuel cell electric vehicles could face is when hydrogen refueling stations shut down for unscheduled maintenance issues, and this could slow the adoption of these zero-emission vehicles. However, the authors pointed to a “prognostics health monitoring” model that they said could help hydrogen refueling stations avoid these shut downs. 

Motorists expect to be able to fuel their vehicles without any problems, and drivers of hydrogen-fueled cars should have the same experience, Jennifer Kurtz, lead author of the paper, said. Kurtz  leads NREL’s Energy Conversion and Storage Systems Center.

“This predictive model can let station operators know in advance when a problem might occur and minimize any disruptions that motorists might experience with hydrogen fueling,” Kurtz said. 

NREL is the DOE’s primary laboratory for research and development connected to renewable energy and energy efficiency. This latest paper was funded by the DOE’s Hydrogen and Fuel Cell Technologies Office.

The research focuses on a specific model called hydrogen station prognostics health monitoring, or H2S PHM, which uses data to reduce the frequency of unscheduled maintenance, and instead increase the frequency of preventive maintenance. The model looks at how many fills the refueling station has completed to figure out the probability that a component will continue working, and can also estimate the remaining useful life of each component, helping to lower maintenance costs. However, this model has its own limitations when looking at the reliability of a hydrogen station, since it cannot predict sudden failures caused by human error. 

One of the most common reasons that hydrogen refueling stations shut down without warning is due to issues with the dispenser system, which includes hoses and dispenser valves, according to the National Fuel Cell Technology Evaluation Center.

Hydrogen refueling stations are still relatively rare in the U.S. As of this year, there were 59 retail hydrogen refueling stations in the U.S., mostly in California, according to the DOE – compared to the 10,000 gasoline stations in the state. 

“With relatively few choices, motorists who rely on hydrogen must be confident their needed fuel is available. Station operators must make any necessary repairs to meet the demands of consumers, but they also must investigate the causes of any failures to avoid future problems,” NREL said. 

However, this could soon be changing. This year, fuel cell electric vehicle manufacturer Nikola Corporation received $58.2 million from different regulatory agencies to set up a hydrogen refueling station network for heavy-duty trucks. And last year, Daimler Truck North America, NextEra Energy Resources and BlackRock Renewable Power announced they had signed a memorandum of understanding to take a closer look at designing, installing and operating a charging network for medium- and heavy-duty battery electric vehicles as well as hydrogen fuel cell vehicles across the nation, with an initial investment of $650 million.

Northeast U.S. solar developer and operator BlueWave received $91 million in financing, which the company says will allow it to achieve long-term ownership and management of its portfolio of projects.

The financing will go toward the construction of five projects featuring dual-use solar development attributes, called agrivoltaics, in Massachusetts. These projects are “strategically implemented to benefit all parties impacted by the projects,” including landowners, farmers and the surrounding community, according to BlueWave. The financing includes a $64 million debt raise with KeyBank, and $27 million tax equity raise with U.S. Bancorp Impact Finance.

The five projects include a 3.6 MW facility in Dighton; 3.5 MW facility in Douglas; 2 MW facility in Haverhill; and 2 MW and 8.6 MW projects in Palmer, Jesse Robertson-DuBois, director of sustainable solar development at BlueWave, told pv magazine USA. 

The projects will use ATI racking and will all be elevated 10’ to accommodate agricultural operations under the arrays, Robertson-DuBois added. Moreover, the systems are spaced more widely than typical, and account for fence setbacks and turning clearances needed for agriculture equipment.

“These design decisions were all made to ensure efficient farm operations. The combination of added height and wider row spacings results in a minimum of 50% light availability for every square foot of ground,” Robertson-DuBois said. 

The project sites include a varied group of crops, pollinator habitats and livestock grazing operations, according to BlueWave. At four of the projects, farming operations will be able to continue uninterrupted beneath the solar arrays, and the fifth includes the creation of a new grazing pasture. All projects are scheduled to come online in 2023, and will be interconnected with National Grid. 

BlueWave’s projects will be included under the Solar Massachusetts Renewable Target (SMART) program, and are expected to save money on the bills of around 770 low-income households. The 3,200 MW declining block incentive program was created by the Massachusetts Department of Energy Resources. Eligible projects must be interconnected by one of the state’s three investor-owned utilities, and are paid tariff-based incentives directly by the utility. 

Agrivoltaics are a combination of farming practices with solar photovoltaic energy production and is expected to become a $9.3 billion market by 2031. Experts at Allied Analytics say that the practice can help address food security while also transitioning to clean energy. The global installed agrivoltaics output rose from 5 MW in 2012 to 2.9 GW in 2020, according to the company. 

Massachusetts is a leader in agrivoltaics, thanks to its SMART solar incentive program, which includes an adder for agrivoltaic systems, Mark Sylvia, chief of staff at BlueWave, told pv magazine USA.

The state’s 2022 Climate Billl also included the creation of an agrivoltaics commission to make recommendations to remove barriers to the further development of agrivoltaic projects, Sylvia added. 

In May 2022, BlueWave announced it had been acquired by Axium Infrastructure, an infrastructure investment management firm with a North American renewables portfolio.

The quote by Robertson-Dubois was changed to say “The combination of added height and wider row spacings results in a minimum of 50% light availability”, rather than “maximum”.

Eos Energy Enterprises, a long-duration zinc-powered energy storage system company based in Pennsylvania, has announced a new $500 million program called AMAZE (American Made Zinc Energy) in a bid to build 8 GWh of annual energy storage production capacity by 2026.

The project has been awarded an up to $398.6 million conditional commitment for a loan guarantee from the U.S. Department of Energy’s (DOE) Loan Programs Office, according to Eos. If that comes through, the loan will fund 80% of the company’s planned expansion, including capital expenditure and other eligible costs, Nathan Kroeker, chief financial officer of Eos, told pv magazine USA. The company’s current semi-automated line is 540 MWh of annual production capacity, and it is currently in the process of ramping up to commercial production at this level, Kroeker said. 

“The issuance of conditional commitment by the DOE was preceded by legal, technical and commercial due diligence by the LPO to evaluate the loan and the project’s potential to meet market demand and commercial and environmental benchmarks,” the company stated. However, the project will need to meet certain milestones and technical, legal and financial conditions before the agency officially funds the loan. 

Eos’ zinc halide storage systems are specifically designed for long-duration energy storage, including utility-scale as well as microgrid applications, Kroeker said. 

“The market needs numerous non-lithium alternatives in order to achieve the green targets that companies, utilities, and state and federal governments have set. Given Eos’ product is non-flammable, it is also suitable for urban and potentially indoor applications,” Kroeker added. 

In 2018, the company relocated its production and supply chain from China back to the U.S., and the battery includes predominantly American components. Because of this, the company can take advantage of direct pay tax credits included under the Inflation Reduction Act (IRA), which was signed by President Biden into law last August.

The implementation of that legislation requires the industry to move with speed and urgency if it is to meet the demand for long-duration energy storage, said Eos CEO, Joe Mastrangelo.

“Project AMAZE should allow Eos to fully commercialize a safe American-made energy storage alternative aimed at creating a resilient, diversified lower carbon energy future,” Mastrangelo said. 

Eos was founded in 2008 and says its technology presents a cost-effective and scalable alternative to other energy storage technologies on the market today. In 2020, the company signed a deal to supply 1 GWh of energy storage systems in projects in the Electric Reliability Council of Texas (ERCOT) market, and another to supply Carson Hybrid Energy Storage with 500 MWh of battery energy storage systems for the California grid. 

Last November, Eos along with Invinity Energy Systems were chosen to provide their systems for a 60 MWh solar-plus-storage microgrid developed by Native American-owned Indian Energy, to provide back-up power to the Viejas Casino and Resort. Eos’ role in the project included providing a 35 MWh zinc battery.

Commercial solar and energy storage company Summit Ridge Energy celebrated the construction of six rooftop community solar projects in Maryland, totaling over 17 MW.

The projects are part of the Maryland Community Solar program – an effort to provide local residents with low-cost, renewable energy – and are expected to generate over 25 million kWh of power annually. They will be sited on the rooftops of industrial assets owned by LBA Logistics, a real estate investment and management firm. 

The first project is expected to come online in the third quarter of this year, according to Summit Ridge Energy. The projects are all rooftop solar, and no trackers were used, Leslie Elder, Summit Ridge Energy’s vice president of political and regulatory affairs, told pv magazine USA. While they won’t be paired with energy storage at this time, “as the Maryland market evolves to incentivize storage, we will be very excited to consider adding storage to these systems,” Elder added. 

Summit Ridge Energy – along with LBA Logistics and commercial buyer’s representative Black Bear Energy, which facilitated the collaboration between the two companies – held a ribbon-cutting ceremony in Rosedale, Maryland.

The company has also expanded a partnership with HASI, a climate solutions investor, to build and operate a 250 MW community solar portfolio. The two companies entered a joint venture in 2019, and this transaction doubles the size of that. Under the new agreement, HASI will help finance Summit Ridge’s pipeline of community solar projects in Illinois and Maryland over the next two years. Summit Ridge estimates that this portfolio of projects will help avoid more than 51,000 metric tons of carbon dioxide emissions annually.

“Our programmatic, client-centric approach delivers long-term value to our partners, and we look forward to supporting the rapid growth of Summit Ridge Energy’s solar pipeline,” said Susan Nickey, chief client officer at HASI. 

Summit Ridge Energy,  launched in 2017, has a development pipeline of more than 2 GW and has deployed over $1.6 billion into clean energy assets over the last six years. The company expects to have more than 400 MW of PV online by the end of this year. 

Community solar could play a key role in the energy transition. Three out of four Americans want to switch to solar, but rooftop solar panels aren’t an option for many residents, either because they live in apartment buildings, are tenants, have shaded roofs, or don’t qualify to finance them, noted Elder. 

“Community solar is solving this issue. Community solar programs allow customers to ”subscribe” to local solar farms and receive the benefits from solar generation. Customers are matched with a local energy project, lowering their utility bills and guaranteeing that more clean energy is generated locally,” said Elder. 

But while community solar is growing rapidly – Wood Mackenzie has forecasted existing markets will grow by an annual average of 8% with nearly 14 GW of cumulative capacity expected by 2028 – not all states are on board yet, Elder said. 

“The US Department of Energy cites a lack of supportive policy and interconnection issues as key barriers,” Elder added. 

Australia-headquartered Allume Energy announced it received a $1.5 million bridge investment from Elemental Excelerator and the Schmidt Family Foundation, which Allume plans to use to deploy its technology and bring rooftop solar to more than 4,000 residents in the Southeast U.S., beginning with solar projects in Florida, Georgia and Mississippi. 

Solar PV systems tend to be designed for one-to-one connections and deploying them in multi-unit buildings can pose unique challenges. Asset owners pay for the systems, but residents benefit from lower utility costs, according to Mel Bergsneider, executive account manager at Allume Energy. Solar PV systems also have a lifespan that exceeds the short-term stays of apartment renters. 

The company’s behind-the-meter technology, called SolShare, helps address this “split incentive” challenge by allocating power to common areas and apartment units. It is able to allocate the solar energy generated by rooftop panels to each grid meter. In addition, it also keeps tabs on the building’s energy demand, and delivers solar energy in a way that maximizes solar consumption and provides bill savings. 

Residents in apartments can lower their utility bills by using on-site solar power and reducing their consumption from the grid, Bergsneider told pv magazine USA. 

“Direct access to solar can protect against increasing utility rates. Each kWh consumed from solar PV helps residents avoid rising electric grid charges,” Bergsneider said.

The company estimates that its technology can help residents save up to 40% on their electricity bills. Participants in its first pilot project in the U.S., in Orlando, saw average annual savings of $1166 per apartment in the first year, the company reported. This included net metering credit savings. Earlier this year, Allume Energy, RENU Communities, and ESA Solar announced the successful commissioning of a solar installation that will generate renewable electricity for the 296-unit apartment complex, Canopy Apartment Villas. The 165 kW DC rooftop solar was installed in two phases on 12 buildings.

The company also has a project in Jackson, Mississippi, and will soon begin installing its third U.S. project in Orlando. The Mississippi project, which was announced in March, is located at a multi-family building with a 22kW solar array, installed by Louisiana-based contractor Solar Alternatives. Allume’s next projects in the South East are continuing into the end of the third quarter and beginning of fourth quarter, Bergsneider said.

Until recently, solar technology has largely been saving money for people who already have it, Cameron Knox, Allume’s CEO and co-founder, said.

“We need to ensure we include everyone in the energy transition. This partnership will ensure low-income communities can benefit from clean, affordable energy from the sun,” Knox added. 

Elemental Excelerator is a non-profit climate technologies investor, with a portfolio of more than 150 companies, while the Schmidt Family Foundation is a philanthropic initiative focused on renewable energy, resilient food systems, and other areas. 

“We originally invested in Allume Energy because they are leaders in bringing affordable solar to affordable housing. We could all use an extra $1,000 a year in our pocketbooks rather than spent on electricity bills,” Dawn Lippert, founder and CEO of Elemental Excelerator, said. 

A coalition of more than 180 conservation, social justice, Indigenous and other organizations last week pushed the Biden Administration to reject applications to build out regional clean hydrogen hubs, warning that building out hydrogen infrastructure will lead to additional greenhouse gas emissions and pollution.

In the letter, the groups – which include the Center for Biological Diversity and Food and Water Watch – said that 95% of hydrogen produced today is from fossil fuels, and all forms of hydrogen production require large amounts of water. 

“To address the climate emergency, the United States must phase out oil and gas production by 2030, – yet nearly all hydrogen production is from fossil gas,” they wrote. 

Hydrogen advocates, however, pushed back against the letter, saying that the U.S. Congress has made a serious commitment to hydrogen hubs through its Bipartisan Infrastructure Law.

“The development of clean hydrogen worldwide is essential to achieve decarbonization, and the U.S. hydrogen hubs are a key step to achieving U.S. decarbonization and climate goals,” Frank Wolak, president and CEO of the Fuel Cell and Hydrogen Energy Association, told pv magazine USA. 

Building out the hydrogen market has been an area of priority for the Biden Administration. The resource is expected to be a critical tool to decarbonize sectors that would otherwise be hard to decarbonize, such as industrial and chemical processes and heavy-duty transportation. 

While the U.S. currently produces about 10 million metric tonnes (MMT) of hydrogen per year, this largely comes from fossil fuels that aren’t paired with carbon capture technologies. The administration is aiming to produce that same amount of hydrogen entirely from clean energy sources by the end of the decade, and is looking to invest $7 billion to create regional hydrogen hubs across the country. Earlier this month, the administration also launched an inter-agency hydrogen task force, to bolster its “whole of government” approach to the sector. 

But these investments have raised concerns among the groups behind the letter. Hydrogen hubs will require a massive buildout of pipelines, and even the slightest rupture could cause explosions, they wrote in the letter. Constructing these pipelines could disrupt ecosystems, and contaminate soil and water, they added. And even in the case of green hydrogen, produced with renewable energy, the amount of water required – 5000 liters per megawatt-hour, according to the letter – would make it unsustainable, especially in areas affected by drought, they said. 

“Calling hydrogen clean energy is a scam to prop up the oil and gas industry,” Silas Grant, a campaigner at the Center for Biological Diversity, said. 

Hydrogen advocates disagree. Investments in hydrogen hubs will be a central driver in scaling the hydrogen economy and helping communities across the country benefit from clean energy investments, good-paying jobs and improved energy security, Kendall Stephenson, manager of policy at the U.S. Chamber of Commerce’s Global Energy Institute, told pv magazine USA.

“Not only would rejecting applications for these hubs completely disregard bipartisan Congressional direction, it would also deprive hard-to-abate sectors of adequate and affordable hydrogen supplies needed to decarbonize,” said Stephenson. 

“No serious stakeholder committed to net zero would take clean hydrogen off the table — it is just too important of a pathway,” she added. 

Customers in Colorado who own a SolarEdge Technologies’ home battery system can now participate in a new virtual power plant (VPP) incentive program run by Xcel Energy.

The initiative – called the Renewable Battery Connect program – will call on home battery owners to discharge power to the home or the grid when electricity demand is especially high, and provide them with financial incentives in return. SolarEdge software will automatically handle the charging and discharging of the battery when called upon to do so. 

VPPs are aggregations of distributed energy resources, and offer many benefits. In an article on the barriers to VPPs, Jigar Shah, director of the Department of Energy’s Loan Programs Office, touted their virtues. “By deploying grid assets more efficiently, an aggregation of distributed resources lowers the cost of power for everybody, especially VPP participants,” Shah wrote.

SolarEdge worked closely with Xcel Energy to design a program that meets Colorado’s specific energy requirements, Peter Mathews, the company’s North America general manager, said.

“The combination of our highly efficient DC-coupled technology and innovative software lays the groundwork for future VPP growth, as we continue to move towards a net-zero economy,” Mathews added. 

Xcel Energy’s Renewable Battery Connect program began in June. Customers who generate clean electricity from their own rooftop solar systems, store it with at-home batteries and participate in grid-management events can play an important role in supporting the electrical grid and generation needs, especially on very hot days when air conditioning units are running, the utility told pv magazine USA. Xcel Energy invests nearly $5.2 million each year in customer rebates for renewable programs such as this one.

Customers who enroll in Xcel Energy’s Renewable Battery Connect program will be given a $500 per KW upfront incentive, working out to $2,500 for one SolarEdge home battery, and an additional $100 for each year that they are part of the program. Customers who meet certain income thresholds or come from disproportionately impacted communities could receive a higher $800 per kW incentive. The program’s enrollment period is five years, and customers could be called upon to discharge power to the home or the grid up to 60 times annually. 

VPPs present the electricity sector with a host of potential benefits. They can reduce reliance on fossil fuel resources, and play a role in electrifying different sectors of the economy. In the report Virtual Power Plants, Real Benefits, RMI estimates that VPPs will reduce peak demand in the country by 60 GW by 2030, and potentially 200 GW by 2050. Moreover, VPPs can reduce yearly power industry costs by $17 billion by the end of the decade, since they can avert the need to build out generation, transmission and distribution infrastructure. 

“Over the next decade, VPPs could play a central role in meeting grid and societal needs,” the report stated. 

However, the report also identified three potential obstacles to the growth of the VPP market – whether regional transmission organizations craft wholesale market rules that fairly compensate VPPs; whether utilities provide retail programs and rates that promote VPPs in areas that are not served by wholesale electricity markets; and the low awareness among customers and policymakers regarding the benefits offered by VPPs. 

In July, SolarEdge announced it had entered a multi-year capacity reservation agreement with global semiconductor company Infineon Technologies, under which Infineon would supply it with components for multiple SolarEdge products. The two companies also plan to work together on developing solar products and other future technologies. 

SolarEdge reported record revenue of $991.3 million in its Q2 earnings report on Aug. 1, 5% higher than the previous quarter and 36% higher than the second quarter of 2022. Solar segment revenues totalled $947.4 million, 38% than the same quarter last year. 

This article was amended on August 28, 2023 to add a statement from Xcel Energy.

The Biden-Harris Administration has launched an inter-agency hydrogen task force designed to advance the administration’s “whole of government” approach to clean hydrogen, Mary Frances Repko, White House deputy national climate advisor, announced during a webinar. 

The task force will be co-chaired by Repko and David Turk, deputy secretary of the U.S. Department of Energy (DOE), and will “ensure that we fully leverage the strengths and capabilities of the U.S. government to develop technologies, implement policy, and overcome barriers to building the clean hydrogen economy,” Repko said. 

Clean hydrogen is expected to play an integral role in achieving a decarbonized energy system. It can be produced in nearly every corner of the country and across a wide range of sectors, and can be a useful tool to decarbonize “hard-to-decarbonize” sectors, like industrial and chemical processes and heavy transportation. It also provides a form of long-duration energy storage. 

In June, the Biden-Harris Administration released a national clean hydrogen strategy and roadmap, which includes strategic opportunities to domestically produce 10 million metric tonnes (MMT) of clean hydrogen annually by the end of the decade, 20 MMT annually by 2040, and 50 MMT annually by 2050. 

The administration is also looking to invest $8 billion in building regional hydrogen hubs, and implement a “game-changing” hydrogen production tax credit, Repko said. 

“The vast opportunities of the clean hydrogen economy extend beyond a few programs – it touches a wide segment of our society and cuts across many of the administration’s priorities,” Repko said.

Under the new task force, federal agencies will coordinate efforts related to hydrogen across multiple areas, Repko said. This includes ramping up outreach with tribal communities and other historically underserved communities. In addition, it will work closely with a spectrum of stakeholders from industry, academia and labor unions, she said. 

Multiple federal agencies are working on clean hydrogen-related initiatives. The DOE leads this area with research and development work on hydrogen delivery, storage and applications in transportation, energy storage, power generation and other sectors; The Department of Defense (DOD) has also conducted hydrogen-related research and development on things like underwater and aerial vehicles, and microgrids. And the Department of Agriculture  implements the Renewable Energy for America Program, which can include hydrogen, and provides loan financing and grants to implement renewable energy systems. 

The U.S. currently produces about 10 MMT of hydrogen annually, but the vast majority of that comes from fossil fuel sources without carbon capture technologies, Turk said. By 2030, the administration wants to produce that same amount of hydrogen, but entirely from clean resources. 

“Just to give you a sense of scale of what we’re talking about, 10 million metric tons of clean hydrogen [is] equivalent to the amount of energy used by every bus and every train in the United States combined,” Turk said.

The U.S. Department of Energy (DOE) recently awarded up to $11.8 million in funding to the California DAC Hub, a consortium of organizations comprised of approximately 40 organizations from across industry, community, tribes, government, technology, national labs, academia, labor, and workforce development. The consortium is looking to build California’s first full-scale direct air capture and storage network of hubs.

The California DAC Hub is being led by CTV Direct, a wholly owned subsidiary of CRC’s Carbon TerraVault that is focused exclusively on DAC plus storage; Kern Community College District (KernCCD), the community benefits plan lead; and EPRI, a non-profit energy research and development institute.

This funding will be used to study a regional carbon management hub in California’s Kern County, following which the consortium plans to build similar facilities in other parts of the state. The group includes nearly 40 organizations, including representatives from industry, government, technology, and labor and workforce development. 

The hub could be able to remove more than 1 million metric tons of carbon dioxide every year, or the equivalent of eliminating 220,000 gasoline vehicles on the road annually. In addition to bringing California closer to its climate goals, each hub could also provide high-paying and permanent jobs and workforce development programs, according to Carbon TerraVault Holdings, a subsidiary of the California Resources Corporation, which assembled the consortium. 

The timeline for getting the hub operational will depend on the timing of further DOE funding for the development and construction stages, Richard Venn, a spokesperson for the California Resources Corporation, told pv magazine USA.

The direct air capture industry is in an early stage and provides a tremendous opportunity for many states and regions to invest in a new clean technology industry that will remove carbon dioxide from the air and deliver significant co-benefits to local communities, Venn added. 

“According to the Intergovernmental Panel on Climate Change (IPCC), carbon removal methods such as DAC are key to mitigation pathways aimed at keeping global warming to below 1.5 degrees Celsius,” said Venn. 

Direct air capture technology involves separating carbon dioxide from the air, and either storing it underground permanently or using it in products that contain carbon, like concrete. At least 27 direct air capture plants have been commissioned worldwide, and plans for another 130 facilities are at various stages of development, according to the International Energy Agency. 

The California funding is part of a larger DOE effort to invest in engineered carbon removal. Last week the agency announced up to $1.2 billion in funding to develop two commercial-scale direct air capture facilities in Texas and Louisiana, which are collectively expected to remove more than 2 million metric tons of carbon dioxide emissions from the atmosphere every year. 

The DOE’s investment lays the foundation for a direct air capture industry that will be crucial to tackling climate change, according to Jennifer Granholm, U.S. Secretary of Energy.

“Cutting back on our carbon emissions alone won’t reverse the growing impacts of climate change; we also need to remove the CO2 that we’ve already put in the atmosphere…” said Granholm. 

The DOE also selected 19 additional projects – including the California hub – to support the earlier stages of project development, such as feasibility assessments. 

“Our research has shown that carbon management, when combined with electrification and clean fuels, delivers the most affordable, resilient and technologically proven path to full carbon neutrality,” said Maryam Brown, president of SoCalGas. The utility’s role in the project includes a front-end engineering design study on transporting the captured carbon to permanent storage. 

The DOE funding will be used in 2024 to conduct studies on the planned facilities in Kern County, Carbon TerraVault said. The consortium could begin developing and constructing the facility in 2025, and plans to put out additional funding requests next year as well.

The opening paragraphs were amended to better explain the mission and leadership of the consortium.

Mote Inc, a Los Angeles, California-based clean energy startup, is planning to build its second biomass-to-hydrogen and carbon sequestration plant in Northern California, in collaboration with the Sacramento Municipal Utility District (SMUD), the company announced last week. 

Mote received $1.2 million in funding from the U.S. Forest Service, the California Department of Conservation, and the California Department of Forestry for the facility, and will work with SMUD – its hydrogen offtake partner – to develop it. The facility should be able to produce roughly 21,000 metric tons of carbon-negative hydrogen annually, which can then be used to generate power or in the transportation sector, according to the company. 

The plant will be designed to use up to 300,000 metric tons per year of wood waste and other forest residue, which would otherwise be burned or sent to a landfill. It would be capable of sequestering more than 450,000 metric tons of carbon dioxide annually, according to Mote; roughly equal to the emissions generated by 100,000 cars every year. 

Mote’s technology is based on taking in biomass waste, which is then reacted with pure oxygen to produce a gas mixture. That gas mixture, once separated and purified, results in bio-hydrogen and permanently storable carbon dioxide, as well as leftover ash that can be sold to fertilizer companies. The technology captures virtually all of the carbon from waste, Mote said. 

Mote’s first such facility is going to be sited near Bakersfield, in California’s Kern County. The company expects to begin constructing the project in 2025, and reach full operational capacity by 2027. 

The Department of Energy Loan Programs Office nvited Mote to submit the second part of an application for the project. The application is for the office’s Title 17 Clean Energy Financing program, through which the office finances projects focused on clean energy deployment and energy infrastructure reinvestment with the broader aim of reducing carbon emissions and air pollution. The program can offer up to 80% of eligible project costs in loan guarantees, according to Mote. 

According to Mote CEO, Joshuah Stolaroff, there is a pressing need for durable, large-scale carbon removal and scalable solutions that provide low-cost, clean hydrogen, and he said that Mote’s technology does both. 

“Our projects in Sacramento and Bakersfield will be the first commercial-scale projects to utilize sustainably sourced biomass for this purpose,” said Stolaroff. 

Bio-hydrogen – or hydrogen synthesized by converting biomass feedstock – can be a good source of carbon-negative hydrogen and a critical tool in achieving net-zero emissions targets, according to a January report from the Center on Global Energy Policy at Columbia University’s School of International and Public Affairs. This is especially the case in sectors that are otherwise hard to decarbonize. In the iron and steel industry, for example, electricity only accounts for 13% of the industry’s total emissions, whereas a majority of its emissions come from blast furnaces. 

“As a result, renewable electricity plays a minor role in decarbonizing this sector,” the report said. 

However, the report noted that bio-hydrogen’s carbon-negative status depends on whether it uses biomass feedstocks that have a very low carbon footprint, and whether it is compatible with carbon capture and storage. 

Nikola Corporation announced a voluntary recall of approximately 209 of its Class 8 Tre battery-electric vehicles, following the preliminary findings of an investigation conducted by Exponent into its battery packs.

The company said Aug. 11 that it was in the process of filing the recall with the National Highway Traffic Safety Administration and will be holding off on selling new battery-electric vehicles for the time being. Nikola manufactures heavy-duty commercial battery-electric vehicles and fuel cell electric vehicles, and is headquartered in Arizona. 

On June 23, Nikola reported in a tweet that a fire had affected multiple battery electric trucks at its Phoenix headquarters, and that the company suspected foul play as a vehicle was seen in the area just before the incident. However, the company now says that internal and third-party evaluations, as well as hours of video footage review, indicate that it’s unlikely the fire was caused by foul play or other external factors. 

Instead, the company reported that following an Aug. 10 presentation from third-party investigator Exponent, it found that a coolant leak in one lithium-ion battery pack likely caused the fire. It said this conclusion was corroborated by a “minor thermal incident” that impacted one battery pack on a truck at its Coolidge, Arizona plant.

“Internal investigations from Nikola’s safety and engineering teams indicate a single supplier component within the battery pack as the likely source of the coolant leak and efforts are underway to provide a field remedy in the coming weeks,” Nikola said.

The company said that so far, only two battery packs out of the more than 3,100 packs on trucks produced until now have experienced an issue. 

Nikola said that while its battery-electric trucks can stay in operation, it is encouraging its customers and dealers to take certain actions to ensure their safety. These include ensuring that the “main battery disconnect” switch is always on, to enable real-time vehicle monitoring, and trying to park trucks outside so that they are better connected to Nikola’s monitoring system.  

“We stated from the beginning that as soon as our investigations were concluded we would provide an update, and we will continue our transparency as we learn more,” said Steve Girsky, CEO of Nikola.

Girsky replaced Nikola’s previous President and CEO Michael Lohscheller, whom the company announced was stepping down from his position on Aug. 4. The company reported that Lohscheller opted to step down because of a family health matter and will continue in an advisory capacity with Nikola until the end of September. 

Separately, Nikola began producing its hydrogen fuel cell electric truck on July 31, and had already received orders for over 200 trucks that it intends to start delivering in September. On the hydrogen front, the company was recently granted $58.2 million in different grants from regulators to build out a network of hydrogen refueling stations for heavy-duty trucks. 

The company said that the voluntary recall will not affect its hydrogen fuel cell electric vehicles, which have a different design. 

Amogy Inc. has successfully tested a first-of-its-kind zero-emission semi-truck that is powered by ammonia, and soon plans to launch commercialization efforts by beginning to produce the product at scale, Seonghoon Woo, the company’s CEO and co-founder, told pv magazine USA. 

Amogy tested its 300 kW semi-truck in early 2023 and its team is now focused on retrofitting a tugboat, which was originally powered with diesel and electric motor, to be the world’s first ammonia-powered vessel, according to Woo. After completing this demonstration, it will launch commercialization efforts and has already started accepting pre-orders from some customers, to be commercially deployed in 2024.

“We are looking at larger production from 2025 or 2026,” said Woo. 

The heavy-duty trucking industry represents 23% of worldwide greenhouse gas emissions from transportation and is particularly difficult to decarbonize, since battery power doesn’t necessarily have the energy density to replace fossil fuels for larger vehicles over long distances. Amogy said its ammonia-to-power technology could present a solution for the sector. 

The company has developed a compact, high-efficiency chemical reactor to split ammonia into hydrogen and nitrogen, and the hydrogen is then sent to a fuel cell to generate power. The technology is easier to integrate into existing infrastructure, according to Woo, and using ammonia as a hydrogen carrier also makes it easier to store and distribute.

“Our technology leverages the superior physical characteristics of liquid ammonia with the performance advantages of hydrogen,” said Woo. 

Amogy started off by integrating its technology into a 5 kW drone in mid-2021, and then a 100 kW tractor in May 2022. With the semi-truck, it has now scaled up to 300 kW and the latest work on the tugboat will use a 1 MW version of its ammonia-to-power system. 

Amogy was founded in 2020 and its investors include Amazon’s Climate Pledge Fund and Saudi Aramco. In May, the company announced a memorandum of understanding with LSB Industries that will focus on encouraging the adoption of ammonia as a marine fuel, beginning with inland waterways transportation in the U.S. The companies plan to roll out a pilot program that combines LSB’s low-carbon ammonia and Amogy’s technology.

Public policy and private investment are shaping the path for ammonia to emerge as a viable clean energy source, and a stable and predictable business and political environment is key to continued investment in the area, Woo said. Many parts of the world – like the U.S. Gulf Coast, Southeast Asia, Australia and the Middle East – are increasing green ammonia production efforts, and Norway has established regulatory frameworks for safe and rational ammonia usage guidelines.  

“Though there will be challenges, the advancement of ammonia-to-power technology must grow alongside the scale of green ammonia production and both must be encouraged by public policy,” Woo said. 

Nikola was granted a total of $58.2 million from various regulatory agencies to build a series of hydrogen refueling stations for heavy-duty trucks, the company announced last week.

Nikola Corporation is a designer and manufacturer of heavy-duty commercial battery-electric vehicles (BEV), fuel cell electric vehicles (FCEV), and energy infrastructure solutions. With headquarters and manufacturing facilities in Arizona, the company began serial production of the hydrogen fuel cell electric truck last month. Earlier this year Nikola launched Hyla, a subsidiary with plans to generate 30 metric tons per day at its Phoenix, Ariz. hydrogen hub, with plans to expand to 150 metric tons in further stages. The first phase of construction of the hub is expected to be completed in the second half of 2024, the company reports.

The largest of the grants to Nikola is $41.9 million from the California Transportation Commission, along with California Department of Transportation to build six refueling stations for heavy-duty hydrogen fuel cell trucks in Southern California. In addition, the company received $3.3 million from the California Energy Commission, $1.6 million from the Mobile Source Air Pollution Reduction Review Committee, $7 million from the Sacramento Metropolitan Air Quality Management District and $4.4 million from the South Coast Air Quality Management District.

“Building an integrated, hydrogen ecosystem to support hydrogen fuel cell electric truck deployment and creating a scalable energy business, is a top priority for us,” said Carey Mendes, president of Nikola Energy.

This May, Nikola announced a partnership between its Hyla brand and infrastructure company Voltera, to develop up to 50 hydrogen stations in North America over the next five years. Work has begun on eight initial stations, Nikola announced while reporting its second quarter earnings. The first one, which located in Ontario, California, is scheduled to begin operating at the end of this year. 

Some of the steps that regulators can take to ease the challenges in building out heavy-duty hydrogen refueling networks include implementing voucher-style programs that reduce the incremental cost upfront for end users, and federal funding that flows to states to offer grants, Mendes told pv magazine USA.

Nikola began serial production of its hydrogen fuel cell electric truck on July 31, the company reported in its second quarter earnings, and had at that point received orders for over 200 hydrogen fuel cell electric trucks from 18 customers. It expects to start delivering the trucks in September. 

Hydrogen as a transportation fuel is a relatively nascent market, especially in terms of the market for heavy-duty fuel cell vehicles, like trucks. As of this year, there were 59 retail hydrogen fueling stations in the U.S., largely clustered in California, according to the U.S. Department of Energy. However, only a small number of these are set up to support heavy-duty hydrogen vehicles. The agency anticipates that as more of these vehicles come on to the roads, the country will need to build out much larger stations. 

“The increase in production and distribution of hydrogen for these stations could improve efficiency and utilization of expensive capital equipment leading to lower fuel costs per kilogram, benefiting both heavy- and light-duty customers,” the Department of Energy’s Alternative Fuels Data Center notes. 

Last year, Daimler Truck North America, NextEra Energy Resources and BlackRock Renewable Power announced they had signed a memorandum of understanding to take a closer look at designing, installing and operating a charging network for medium- and heavy-duty battery electric vehicles as well as hydrogen fuel cell vehicles across the nation, with an initial investment of $650 million. The companies planned to initially focus on charging infrastructure for medium- and heavy-duty electric vehicles, and then hydrogen fueling stations.