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ZeroAvia completes $116m Series C

The UK Infrastructure Bank joined the round as a cornerstone-level investor.

ZeroAvia has completed its Series C funding round at a total of $116m, according to a news release.

The UK Infrastructure Bank joins the round as a cornerstone-level investor alongside co-leads Airbus, Barclays Sustainable Impact Capital and NEOM Investment Fund (NIF) as announced in September, with the Series C round set to accelerate the company’s journey to certification of its first engines and advance R&D that will scale the clean propulsion technology for larger aircraft.

ZeroAvia is starting with hydrogen-electric engines to support a 300-mile range in 9–19 seat aircraft by the end of 2025, and up to 700-mile range in 40–80 seat aircraft by 2027. Founded in California and now with thriving teams also in Everett, WA and the United Kingdom, ZeroAvia has secured experimental certificates to test its engines in three separate testbed aircraft with the FAA and CAA and passed significant flight test milestones.

The financing supports the UK’s status as a market leader in research and development in both aviation and hydrogen and will support ZeroAvia’s ambitious growth plans in the UK.

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Hydrofuel Canada issued US patents for micro ammonia production

Hydrofuel says its technology can significantly reduce the overall cost of green ammonia and the hydrogen in it to 50% of the cost of hydrogen produced via current electrolysis technologies.

Hydrofuel Canada Inc. has been issued US Patent 11,885,029 “Systems and Methods for Forming Nitrogen-Based Compounds” and has completed of their Micro Ammonia Production System (MAPS 1.0) commercial prototype, enabling high-yield, sustainable ammonia synthesis from air and water with unprecedented efficiency using a gas-phase electrochemical process.

The MAPS 1.0 and 2.0 technologies significantly reduce the costs and energy requirement of making ammonia (NH3) compared to traditional methods, according to a news release. Multiple 381 ton per year units can be combined to operate in series or parallel to increase capacity.

The US$700,000 MAPS 1.0 version uses externally produced hydrogen (H2) to synthesize with nitrogen from air to make ammonia.

The US$850,000 MAPS 2.0 system represents a major breakthrough in the production of green hydrogen and ammonia, as it addresses one of the biggest challenges in hydrogen production – the high cost of electrolysis. By combining hydrogen and nitrogen production in a single unit, MAPS 2.0 eliminates the need for separate production processes, significantly reducing the overall cost of green ammonia and the hydrogen in it to 50% of the cost of hydrogen produced via current electrolysis technologies. All Capex and Opex costs quoted exclude any government incentives or tax credits.

Hydrofuel’s MAPS 2.0 Opex, Capex, Customer Deposit (CNW Group/Hydrofuel Canada Inc.)

“We are thrilled to announce the issuance of our US patent for MAPS 1.0 and the completion of our commercial prototype” said Greg Vezina, Chairman and CEO of Hydrofuel Canada. “This is a major milestone and a significant step towards making clean energy and fertilizer more affordable and accessible with MAPS 1.0 units expected to be available by the spring of 2025. With MAPS 2.0 expected to be released in the summer of 2025, customers will be able to produce and store green hydrogen in ammonia at a fraction of the cost, making it a game-changer in the clean energy and fertilizer industries. We will soon announce details of our pre-order campaign that will enable customers to place a small deposit on one of our MAPS units for early delivery.”

The company is currently in talks with potential partners and investors to bring MAPS 1.0 and 2.0 to the market and make a significant impact in the clean energy and fertilizer sectors. With the US patent and commercial prototype completed, Hydrofuel Canada is one step closer to achieving their goal of making green energy and chemicals more affordable and accessible for all.

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IEA report outlines case for cost reductions in e-fuels

The International Energy Agency assesses needed cost reductions, resources and infrastructure investments for achieving a 10% share of e-fuels in aviation and shipping by 2030.

The International Energy Agency’s report on the role of e-fuels in decarbonizing transport finds that e-fuels’ cost gap with fossil fuels could substantially reduce by 2030, an important finding for the advancement of a family of emerging e-fuel technologies. 

In the report, which was published last month, the IEA aims to assess the implications of growth in e-fuels in terms of needed cost reductions, resources and infrastructure investments of an assumed goal of achieving a 10% share of e-fuels in aviation and shipping by 2030. 

For instance, the cost of low-emission e-kerosene might drop to $50/GJ ($2,150 per ton), making it competitive with biomass-based sustainable aviation fuels – but still 2 – 3x more expensive than fossil-based fuels. 

The costs for low-emission e-methanol and e-ammonia could also decrease, opening the door for their use as low-emission fuels in shipping. Interestingly, the production of e-fuels for aviation will also result in a significant amount of e-gasoline as a by-product, the report notes.

In terms of impact on transport prices, a 10% share of low-emission e-fuels would only modestly increase the cost of transport, according to the report. For example, e-kerosene would raise the ticket price of a flight using 10% of e-fuels by only 5%. 

However, the adoption of e-methanol and e-ammonia in shipping will necessitate significant investments in infrastructure and ships. The overall cost for a fully e-ammonia or e-methanol-fueled container ship would be 75% higher than a conventional fossil-fuel-powered ship, yet this represents just 1-2% of the typical value of goods transported in these containers.

The production of e-fuels generally suffers from low efficiency due to multiple conversion steps and losses, leading to high resource and infrastructure demand, according to the report. Producing significant amounts of low-emission e-fuels could increase the demand for renewable electricity by about 2,000 TWh/yr by 2030. This represents about one-fifth of the growth of low-emission electricity expected in this decade under certain policy scenarios. 

The production of e-fuels can exploit the potential of remote locations with high-quality renewable resources and vast land available for large-scale projects. However, achieving a 10% share of e-fuels in aviation and shipping would require a significant increase in electrolyser capacity, equivalent to the entire size of the global electrolyser project pipeline to 2030.

The accelerated deployment of low-emission e-fuels for shipping would require substantial investments in refueling infrastructure and vessels, especially for e-ammonia or e-methanol. Achieving a 10% share in shipping would demand approximately 70 Mt/yr of these fuels. The financial investment in shipping capacity and bunkering infrastructure would be substantial, yet represent less than 5% of the cumulative shipbuilding market size over the period 2023-2030.

Producing carbon-containing low-emission e-kerosene and e-methanol would necessitate a massive increase in CO₂ utilization, with significant potential synergy with biofuels production. Around 200 Mt CO₂ would be required for a 10% share of e-kerosene in aviation and 150 Mt CO₂ for the same share in shipping if using e-methanol. 

Access to CO₂ is a major constraint for carbon-containing low-emission e-fuels, and the best wind and solar resources are not always co-located with significant bioenergy resources. Direct air capture (DAC) of CO₂ could provide an unlimited source of CO₂ feedstock without geographic constraints, but it is expected to remain a high-cost option in 2030, the report projects.

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Canada to fund CAD 800m for clean fuel projects

60 projects have been selected to receive funding through Canada’s CAD 1.5bn Clean Fuels Fund.

Canadian Minister of Natural Resources Jonathan Wilkinson announced that approximately 60 projects have been selected to receive funding under the Government of Canada’s CAD 1.5bn Clean Fuels Fund (CFF).

These projects represent a first tranche of the highest-ranking applications from last year’s call for proposals and have a total combined value of more than CAD 3.8bn. They include production facilities, as well as feasibility and front-end engineering and design studies, spanning seven jurisdictions and covering five different fuel types.

The federal government is undertaking negotiations to finalize the terms of funding for each project, and the total federal investment in these projects will be up to CAD 800m. This funding will help project proponents address critical barriers to growth in the domestic clean fuels market and lays the groundwork for the low-carbon fuels of the future.

A second tranche of projects, from last year’s call for proposal, is currently being reviewed, with funding decisions expected to be finalized in December. Once successful applicants have been informed, Natural Resources Canada will start contribution agreement negotiations.

Canada’s clean fuels industry is rapidly growing, owing to the global demand to reduce greenhouse gas emissions and bolster energy security. The importance of continued investment into the production, development and distribution of clean fuels together with their infrastructure and technology is clear, as Canada strives to position itself as a global leader with investments such as the CFF.

At today’s announcement, Minister Wilkinson also highlighted a combined investment of more than $8.8m to six organizations for 10 hydrogen and natural gas refuelling stations to help accelerate the decarbonization of road transportation. Federal funding for these projects was provided through Natural Resources Canada’s Zero-Emission Vehicle Infrastructure Program (ZEVIP) and the Electric Vehicle and Alternative Fuel Infrastructure Deployment (EVAFIDI).

The funding under ZEVIP and EVAFIDI includes:

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Exclusive: Appalachian biogas firm seeking project debt

An RNG developer based in Appalachia with projects across the US is seeking project debt financing.

Northern Biogas, the West Virginia-based developer and operator of anaerobic digester and RNG facilities, is independently seeking debt for its project pipeline, according to two sources familiar with the matter.

Backed by HIG Capital, Northern Biogas serves diary, landfill, food waste and municipal projects. The company has raised some $200m in debt with assistance from alternative energy finance provider Pathward National Association, one source said. Project debt has typically been raised in tranches of $20m to $30m for individual projects.

Northern Biogas’ portfolio includes five dairy farm projects under construction in Wisconsin and one in Michigan, according to the company’s website. The company has a presence in Texas and Colorado as well.

Representatives of the company did not respond to requests for comment.
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Inside Intersect Power’s green hydrogen plans

California-based renewable energy developer Intersect Power anticipates huge capital needs for a quartet of regional energy complexes co-locating wind and solar with green hydrogen production in the Texas Gulf Coast, California and the American West.

Intersect Power, a solar developer that completed a $750m capital raise last year, is developing four large-scale green hydrogen projects that could eventually be spun off into a separate company, CEO Sheldon Kimber said in an interview.

Four regional complexes of 1 GW or more, co-located with renewables, are in development, he said. The first phases of those, totaling several hundred megawatts, will come online between 2026 and 2028.

Initial offtake markets include transportation, sustainable aviation fuel, and hydrogen for industrial use, Kimber said. Ultimately Intersect is aiming to serve ammonia exporters in the US Gulf Coast, particularly those exporting to Japan, Kimber said, adding that the company could contract with ammonia producers. He recently wrapped up a nine-day, fact-finding trip to Japan to better understand what he believes will be the end market for Intersect’s green ammonia.

“If you don’t know who your customer’s customer is, you’re going to get a bad deal,” Kimber said.

Intersects projects under development involve behind-the-meter electrolysis, co-located with Intersect’s wind and solar generation plants. In 2021 the company signed an MOU with electrolyzer manufacturer Electric Hydrogen. The contract is for 3 GW.

Intersect controls the land and is in the process of permitting the four projects, located in Texas, California and another western US location that Kimber declined to name. The primary focus now is commercial development of the offtake and transportation, he said.

‘Boatload of equity’

Kimber said the company will be ready to announced details of the projects when they are ready to seek financing. He estimates that upwards of $12bn will need to be raised for the package of complexes.

“There’s going to be an enormous need for capital,” Kimber said. Debt will make up between 60% and 90% of the raising, along with “a boatload of equity,” he said. Existing investors will likely participate, but as the numbers get bigger new investors will be brought on board.

Intersect has worked with BofA Securities and Morgan Stanley on past capital raise processes, and also has strong relationships with MUFG and Santander.

Moving forward the company could have a broader need for advisory services and could lend knowledge of the sector in an advisory capacity itself, Kimber said.

“The scope and scale of what we’re doing is big enough and the innovative aspect of what we’re doing is advanced enough that I think we have a lot we can bring to these early-stage financings,” Kimber said. “I think we’re going to be a good partner for advisory shops.”

In the short term Intersect has sufficient equity from its investors and is capitalized for the next 18-to-24 months, Kimber said. Last summer the company announced a $750m raise from TPG Rise Climate, CAI Investments and Trilantic Energy Partners North America.

“People don’t want to pay ahead for the growth in fuels,” Kimber said, adding that reaching commercial milestones will build a compelling valuation.

Intersect could spin off its hydrogen developments to capitalize them apart from renewables, Kimber said.

“Every single company in this space is looking at that,” he said. “Do you independently finance your fuels business?”

Avoiding the hype

Right now the opportunity to participate in hydrogen is blurry because there is so much hype following passage of the IRA, Kimber said. Prospective investors should be focused on picking the right partners.

“What you’re seeing right now is everybody believing the best thing for them,” Kimber said, noting that his company has decided to keep relatively quiet about its activities in the clean fuels space to avoid getting caught up in hype. “The IRA happened, and every electrolyzer company raised their prices by fifty percent.”

Of those companies that have announced hydrogen projects in North America, Kimber said he believes only a handful will be successful. Those companies that have successfully developed renewables projects of more than 500 MW are good candidates, as are companies that have managed to keep a fluid supply chain with equipment secured for the next five years.

“That is a very short list,” he said.

Lenders on the debt side will want to start determining how projects will get financed, and which projects to finance, in the next 18 months, Kimber said.

Finding those who have been innovating on the front-end for years and not just jumped in recently is a good start, Kimber said.

“Hydrogen will happen, make no mistake,” Kimber said. He pointed to the recent European directive that 45% of hydrogen on the continent be green by 2030 and Japan’s upcoming directive to potential similar effect. Once good projects reach critical points in their development they will start to trade, probably in late 2024, he said.

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Turnt up about turndown ratios

Optimizing electrolysis for renewables depends not just on how far you can turn the machine up, but how far you can turn it down. We asked electrolyzer makers: how low can you go?

Optimizing electrolysis for renewables depends not just on how far you can turn the machine up, but how far you can turn it down.

A consensus is growing around the importance of turndown ratios for electrolyzers, with a variety of use cases for green hydrogen requiring the machines to be run at low levels during periods of high power pricing.

Proton exchange membrane (PEM) electrolyzers are known for their ability to quickly ramp production up and down, but manufacturers of all stripes have begun to tout their technologies’ turndown ratios, with implications for capital costs and the levelized cost of producing hydrogen from renewable power.

Simply put, some electrolyzer plant operators will likely seek to lower hydrogen production during periods of high power pricing, since the cost of electricity is the largest operating expense. But cycling the electrolyzers completely off and on can lead to added system degradation, giving importance to the ability of the machines to run at low levels.

A study from the National Renewable Energy Laboratory (NREL) analyzes a US grid buildout through 2050, noting favorable locations and seasonality for power pricing as something of a guideline for green hydrogen development. The study notes that the lowest achievable turndown ratio is a main factor in minimizing hydrogen levelized cost along with the number of hours a system can operate at that minimum level – something that applies to all types of electrolyzers.

“When you start to look at hourly costs from the data in different locations, you see that all of this renewable buildout is going to create opportunities in given locations where you going to have a lot of renewable generation and not a lot of load on the system and that’s going to drive the cost for that energy down,” said Alex Badgett, an author of the study at NREL.

To be sure, the fast-moving technological environment for electrolysis leaves open the possibility for efficiency gains and disruptive innovation. And a variety of factors – balance of plant, energy efficiency, system degradation – also influence plant economics. But the lowest possible turndown ratios will drive opportunities for green hydrogen developers, Badgett said.

ReSource reviewed available spec sheets for electrolyzer providers and asked every maker of PEM and SOEC systems to detail the turndown capabilities of their machines. Alkaline electrolyzers were left out of the analysis given their more limited load flexibility, as their separators are less effective at preventing potentially dangerous cross-diffusion of gasses. Some manufacturers are fully transparent regarding turndown ranges while others declined to comment or did not reply to inquiries.

‘Not trivial’

In designing projects, developers are analyzing hourly energy supply schedules and pairing the outlook with what is known about available technology options.

“Some electrolyzers like to operate at half power, and others like to operate at full power, and in any given system, you can have between 10 and 50 electrolyzers wired and plumbed in parallel,” said Mike Grunow, who leads the Power-to-X platform at Strata Clean Energy.

“Our thought process even goes down to: let’s say you have to operate the H2 plant at 25% throughput. Do you operate all of the electrolyzers at 25%, or do you turn 75% of the electrolyzers off and only operate 25% at full power?”

The difference in the schemes, he added, is “not trivial as each technology has different efficiency curves and drivers of degradation.”

Different use cases for the hydrogen derivative, meanwhile, lead to different natural selection of technologies, Grunow said, adding that the innovation cycle is now happening every 12 months, requiring a close eye on advances in technology. 

Electrolyzer start-up Electric Hydrogen, a maker of PEM electrolyzers, is commercializing a 100 MW system that can turn down to 10%, according to Jason Mortimer, SVP of global sales at the company.

HyAxium, another start-up, can turn its system down to 10%, according to its materials. Norway-based Hystar, which recently announced plans to build a plant in the US, also promotes a 10% turndown ratio.

A more established PEM electrolyzer provider, Cummins, advertises turndown ratios of 5% for its machines. Sungrow Power, a China-based manufacturer, similarly advertises 5% for PEM electrolyzers.

Siemens Energy has a minimum turndown ratio per stack of 40%, but for a single system it can be less in exceptional cases, according to Claudia Nehring, a company spokesperson.

“We focus on large systems” – greater than 100 MW – “and currently consider this value to be appropriate, taking into account the optimization between efficiency, degradation and dynamics, but are working on an improvement,” she said via email.

ITM Power declined to provide details but said its turndown capabilities are “to be expected” for a market leader in this technology. Materials from German-based H-Tec Systems note a modulation rate down to 10%.

Additional PEM makers Nel, Ohmium, Elogen, H2B2, Hoeller Electrolyzer, Plug Power, Shanghai Electric, and Teledyne Energy Systems did not respond to requests for information.

PEM alternatives

Other forms of electrolysis can also ramp dynamically. And some project developers point to PEM’s use of iridium, part of the platinum metals family, as a drawback due to potential scarcity issues.

Verdagy, for example, has developed an advanced alkaline water electrolysis (AWE) system called eDynamic that it says takes the best of PEM and alkaline technologies while designing out the downsides.

The company’s technology “addresses the barriers that limited traditional AWE adoption by using single-element cells that can operate efficiently at high current densities,” executives said in response to emailed questions. 

“The ability to operate at very high current densities, coupled with a balance of stack and balance of plant optimized for dynamic operation, allow Verdagy’s electrolyzers to operate across a very broad range spanning 0.1-2.0 A/cm2,” they said.

In other words, the machine can turn down to 5%, part of the design that enables operators “to modulate production to take advantage of time-of-day pricing and/or fluctuations in energy production.”

Meanwhile, German-based Thysenkrupp Nucera, another maker of advanced water electrolyzers, advertises a 10% turndown ratio.

SOEC

A relatively new electrolysis technology, the solid oxide electrolyzer cell has also proven to be capable of low turndown ratios. Solid oxide electrolysis is particularly attractive when paired with high-temperature industrial processes, where heat can be captured and fed back into the high-temperature SOEC process, making it more efficient.

Joel Moser, the CEO of First Ammonia, said he chose SOEC from Denmark-based Haldor Topsoe in part because the machines can be turned completely off with no degradation, as long as you keep them warm.

“Generally speaking we expect to ramp up and ramp down between 100% and 10%,” he said. “We can turn them off as long as we keep them warm, and then we can turn them right back on.”

Still, SOEC systems are not without challenges.

“Low stack power and high operating temperature, which in turn requires more ancillary equipment to operate the electrolyzer, are widely viewed as the main drawbacks of SOEC technology,” according to a report from the Clean Air Task Force, which explores SOEC technology and its commercial prospects. “SOEC systems are also considered to have a shorter operating life due to thermal stress.”

Additional makers of SOEC machines Bloom Energy, Ceres, Elcogen, Genvia, SolydERA, and Toshiba did not respond to inquiries.

At NREL, researchers are watching for more automation and scale in the electrolyzer production process to bring costs down. Increasing efficiency through balance-of-plant improvements is another opportunity to reduce system costs.

In addition, more analysis of how large electrolyzer projects will impact the future electrical grid is required, according to Badgett.

The NREL team modeled the hourly marginal cost at any given time in any location in the US, but the model assumes that the electrolyzer takes energy without impacting the cost of energy.

“When we start to get to gigawatt-scale electrolysis,” he said, “that’s going to significantly impact prices, as well as how the grid is going to build out.”

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