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Fenton Mobility Products and Ideanomics to bring hydrogen-powered transit buses to New York

The more than $2.2m order is for five hydrogen-powered, zero-emission transit vans for the Rochester-Genesee Regional Transportation Authority

Ideanomics has been selected by Fenton Mobility Products as its partner to build five hydrogen-powered, zero-emission transit vans for the Rochester-Genesee Regional Transportation Authority, according to a news release.

The value of RGRTA’s order exceeds $2.2m. The cost of the buses is covered with funds from a $23m grant the RGRTA received from the U.S. Department of Transportation to deploy hydrogen fuel cell buses.

Under the terms of the agreement, Fenton Mobility will deliver a pilot hydrogen fuel cell battery electric-powered high-headroom van to the RGRTA. Once the pilot vehicle completes the FTA-mandated Altoona durability testing period and is shown to meet all requirements, production will commence on five additional vehicles to be delivered by 1Q24.

Ideanomics, through its subsidiary US Hybrid, will assemble the hydrogen fuel cell propulsion system and manufacture associated components at its engineering facility in Torrance, California. Fenton Mobility will install the hydrogen propulsion kit into the vans.

“Fenton is known for delivering the best solutions for public transportation, and Ideanomics has some of the best zero-emission products and technology,” Macy Neshati, Chief Commercial Officer at Ideanomics, said in the release.

New York State has set a goal for several transit systems across the state – including RGRTA – to fully transition their fleets to zero-emission by 2035. The state and RGRTA see hydrogen as an important clean energy solution to achieve these goals.

Ideanomics is part of a coalition to build zero-emission, hydrogen-powered shuttle buses, and has supplied hydrogen-powered buses to the County of Hawai’i Mass Transit Agency.

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United, Tallgrass, and Green Plains form JV to develop SAF from ethanol

The JV – Blue Blade Energy – aims to develop and then commercialize a novel sustainable aviation fuel technology that uses ethanol as its feedstock.

United Airlines, Tallgrass, and Green Plains Inc. today announced a new joint venture – Blue Blade Energy – to develop and then commercialize a novel sustainable aviation fuel (SAF) technology that uses ethanol as its feedstock.

If the technology is successful, Blue Blade is expected to proceed with the construction of a pilot facility in 2024, followed by a full-scale facility that could begin commercial operations by 2028. The offtake agreement could provide for enough SAF to fly more than 50,000 flights annually between United’s hub airports in Chicago and Denver.*

Blue Blade’s new SAF technology was developed by researchers at the U.S. Department of Energy’s Pacific Northwest National Laboratory (PNNL), a leading center for technological innovation in sustainable energy. SAF, which uses non-petroleum feedstock, is a low-carbon alternative to traditional jet fuel that offers up to 85%** lower lifecycle greenhouse gas emissions.

“The production and use of SAF is the most effective and scalable tool the airline industry has to reduce carbon emissions and United continues to lead the way,” said United Airlines Ventures President Michael Leskinen. “This new joint venture includes two expert collaborators that have the experience to construct and operate large-scale infrastructure, as well as the feedstock supply necessary for success. Once operational, Blue Blade Energy has the potential to create United’s largest source of SAF providing up to 135 million gallons of fuel annually.”

United, Tallgrass, and Green Plains will each provide their unique industry expertise to help develop the joint venture. Under this collaborative approach:

  • Tallgrass will manage research and development of the technology, including pilot plant development, and will manage the construction of the production facility.
  • Green Plains will supply the low-carbon ethanol feedstock, and use its ethanol industry expertise to manage operations once the pilot facility is constructed.
  • United Airlines will assist with SAF development, fuel certification and into-wing logistics, and has also agreed to purchase up to 2.7 billion gallons of SAF produced from the joint venture.

“At Tallgrass, we are striving to innovate how we deliver the energy that powers our nation and enables our quality of life,” said Alison Nelson, Vice President, Business Development at Tallgrass. “Air travel uniquely connects people and improves lives, and the advancement of this novel SAF technology presents a meaningful opportunity to reduce emissions from aviation.  We are excited to partner with industry leaders United Airlines and Green Plains on this initiative.”

If the technology is commercialized, the location of Blue Blade’s initial plant would allow easy access to low-carbon feedstock from Green Plains’ Midwest ethanol production facilities. While the initial SAF facility intends to use ethanol, the technology has the capability to work with any alcohol-based feedstock as its fuel source.

“Our transformation to a true decarbonized biorefinery model has positioned Green Plains to help our customers and partners reduce the carbon intensity of their products by producing low-carbon proteins, oils, sugars and now decarbonized ethanol to be used in SAF,” said Todd Becker, President and CEO of Green Plains. “This partnership with world class organizations like United Airlines and Tallgrass, shows the value creation that is possible with our low-carbon platform. The potential impact of this project is a gamechanger for US agriculture, aligning a strong farm economy and a robust aviation transport industry focused on decarbonizing our skies.”

Blue Blade Energy marks one of the largest direct investments from United Airlines Ventures (UAV), United’s corporate venture arm, into SAF. Launched in 2021, UAV targets startups, upcoming technologies, and sustainability concepts that will complement United’s goal of net zero emissions by 2050 without relying on traditional carbon offsets. United has aggressively pursued strategic investments in SAF producers and revolutionary technologies including carbon capture, hydrogen-electric engines, electric regional aircraft and air taxis.

*Assuming current regulations requiring SAF to be blended with conventional jet fuel are removed to allow for the use of unblended SAF.
**Based on United’s current SAF supply

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Australia’s Hysata raises $29m Series A

Australian company Hysata has raised an oversubscribed Series A funding round of $29m USD.

Australian company Hysata has raised an oversubscribed Series A funding round of $29m USD.

Virescent Ventures led the funding round on behalf of the Clean Energy Finance Corporation (CEFC) (Aus), with participation from Kiko Ventures (UK), IP Group Australia, Vestas Ventures (Denmark), Hostplus (Aus) and BlueScope (via its ventures arm BlueScopeX TM) (Aus).

Assembling such a high profile and high impact list of investors underlines the significance of the transformation that Hysata is bringing to the green hydrogen industry, according to a press release.

The Hysata electrolyser operates at 95% system efficiency (41.5 kWh/kg), delivering a giant leap in performance and cost over incumbent technologies, which typically operate at 75% or less. This high efficiency, coupled with the simple approach to mass manufacturing and low supply chain risk puts the company on a path to delivering the world’s lowest cost green hydrogen.

Funding from the Series A round will be used to grow the Hysata team and develop a pilot manufacturing facility.

“Our mission is to redefine the economics of green hydrogen production through our innovative proprietary electrolyser technology. The support of this international syndicate of clean energy practitioners and investors validates our core technology and our approach to scaling and mass manufacture,” said Paul Barrett, CEO of Hysata.

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Cleveland-Cliffs submits application for front-end engineering design for large-scale carbon capture

The steel and iron ore company’s Burns Harbor project in Indiana aims to capture up to 2.8 million tons of CO2 per year from blast furnace gas with a net carbon capture efficiency of at least 95%.

Cleveland-Cliffs Inc. announced that its initial phase of research being conducted with funding from the U.S. Department of Energy’s (DOE) Office of Clean Energy Demonstrations (OCED) is coming to a close. Based on the results of the initial study, Cleveland-Cliffs has submitted an application on Monday, Dec. 5 for funding from the DOE’s OCED for the next phase of research for the front-end engineering design (FEED) for large-scale carbon capture at its Burns Harbor integrated iron and steel facility located in Northwest Indiana, according to a news release.

The company’s Burns Harbor project aims to capture up to 2.8 million tons of CO2 per year from blast furnace gas with a net carbon capture efficiency of at least 95%. The proposed FEED would be completed over a period of 24 months. The study would be funded 50 percent by Cleveland-Cliffs and 50 percent by the DOE through the Bipartisan Infrastructure Law appropriations, which is part of a broader government approach to fund domestic commercial-scale Carbon Capture and Sequestration technology.

Cleveland-Cliffs has existing technical partnerships with the DOE and is the only American steel producer participating in the DOE Better Climate Challenge initiative. The Company is the largest industrial energy user in the DOE’s Better Plants program. Through DOE’s Better Climate Challenge, organizations join a network of market leaders that are stepping forward to work with DOE to plan for their organization’s future success by reducing GHG emissions and sharing replicable pathways to decarbonization.

Cleveland-Cliffs is the largest flat-rolled steel producer in North America. Founded in 1847 as a mine operator, Cliffs also is the largest manufacturer of iron ore pellets in North America.

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Interview: Vinson & Elkins’ Alan Alexander on the emerging hydrogen project development landscape

Vinson & Elkins Partner Alan Alexander, whose clients include OCI and Lotus Infrastructure, has watched the hydrogen project development space evolve from a fledgling idea to one that is ready for actionable projects.

Vinson & Elkins Partner Alan Alexander, whose clients include OCI and Lotus Infrastructure, has watched the hydrogen project development space evolve from a fledgling idea to one that is ready for actionable projects.

In the meantime, a number of novel legal and commercial issues facing hydrogen project developers have come to the forefront, as outlined in a paper from the law firm this week, which serves as a guide for thinking through major development questions that can snag projects.

In an interview, Alexander, a Houston-based project development and finance lawyer, says that, although some of the issues are unique – like the potential for a clean fuels pricing premium, ownership of environmental attributes, or carbon leaking from a sequestration site – addressing them is built on decades of practice.

“The way I like to put it is, yes, there are new issues being addressed using traditional tools, but there’s not yet a consensus around what constitutes ‘market terms’ for a number of them, so we are having to figure that out as we go,” he says.

Green hydrogen projects, for example, are “quite possibly” the most complex project type he has seen, given that they sit at the nexus between renewable electricity and downstream fuels applications, subjecting them to the commercial and permitting issues inherent in both verticals.

But even given the challenges, Alexander believes the market has reached commercial take-off for certain types of projects.

“When the hydrogen rush started, first it was renewables developers who knew a lot about how to develop renewables but nothing about how to market and sell hydrogen,” he says. “Then you got the people who were very enthusiastic about developing hydrogen projects but didn’t know exactly what to do with it. And now we’re beginning to see end-use cases develop and actionable projects that are very exciting, in some cases where renewables developers and hydrogen developers have teamed up to focus on their core competencies.”

A pricing premium?

In the article, Vinson & Elkins lawyers note that commodities pricing indices are not yet distinguishing between low-carbon and traditional fuels, even though a clean fuel has more value due to its low-carbon attributes. The observation echoes the conclusion of a group of offtakers who viewed the prospect of paying a premium for clean fuels as unrealistic, as they would need to pass on the higher costs to customers.

Eventually, Alexander says, the offtake market should price in a premium for clean products, but that might depend in the near term on incentives for clean fuels demand, such as carbon offsets and levies, like the EU’s Carbon Border Adjustment Mechanism.

“Ultimately what we need is for the market to say, ‘I will pay more for low-carbon products,’” he says. “The mindset of being willing to pay more for low-carbon products is going to need to begin to permeate into other sectors. 30 or 40 years ago the notion of paying a premium for an organic food didn’t exist. But today there are whole grocery store chains built around the idea. When the consumer is willing to pay a premium for low-carbon food, that will incentivize a farmer to pay a premium for low carbon fertilizer and ammonia, which will ultimately incentivize the payment of a premium for low-carbon hydrogen. The same needs to repeat itself across other sectors, such as fuels and anything made from steel.”

The law firm writes that US projects seeking to export to Europe or Asia need to take into account the greenhouse gas emissions and other requirements of the destination market when designing projects.

In the agreements that V&E is working on, for example, clients were first focused on structuring to make sure they met requirements for IRA tax credits and other domestic incentives, Alexander says. Meanwhile, as those clean fuels made their way to export markets, customers were coming back with a long list of requirements, “so what we’re seeing is this very interesting influx” of sustainability considerations into the hydrogen space, many of which are driven by requirements of the end-use market, such as the EU or Japan.

The more stringent requirements have existed for products like biofuels for some time, he adds, “but we’re beginning to see it in hydrogen and non-biogenic fuels.”

Sharing risk

Hydrogen projects are encountering other novel commercial and legal issues for which a “market” has not yet been developed, the law firm says, especially given the entry of a raft of new players and the recent passage of the Inflation Reduction Act.

In the case of a blue hydrogen or ammonia project where carbon is captured and sequestered but eventually leaks from a geological formation, for example, no one knows what the risk truly is, and the market is waiting for an insurance product to provide protection, Alexander says. But until it does, project parties can implement a risk-sharing mechanism in the form of a cap on liabilities – a traditional project development tool.

“If you’re a sequestration party you say, ‘Yeah, I get it, there is a risk of recapture and you’re relying on me to make sure that it doesn’t happen. But if something catastrophic does happen and the government were to reclaim your tax credits, it would bankrupt me if I were to fully indemnify you. So I simply can’t take the full amount of that risk.’”

What ends up getting negotiated is a cap on the liability, Alexander says, or the limit up to which the sequestration party is willing to absorb the liability through an indemnity.

The market is also evolving to take into account project-on-project risk for hydrogen, where an electrolyzer facility depends on the availability of, for example, clean electricity from a newly built wind farm.

“For most of my career, having a project up and reaching commercial operations by a certain date is addressed through no-fault termination rights,” he says. “But given the number of players in the hydrogen space and the amount of dollars involved, you’re beginning to see delay liquidated damages – which are typically an EPC concept – creep into supply and offtake agreements.”

If a developer is building an electrolyzer facility, and the renewables partner doesn’t have the wind farm up and running on time, it’s not in the hydrogen developer’s interest to terminate through a no-fault clause, given that they would then have a stranded asset and need to start over with another renewable power provider. Instead, Alexander says, the renewables partner can offset the losses by paying liquidated damages.

Commercial watch list

In terms of interesting commercial models for hydrogen, Alexander says he is watching the onsite modular hydrogen development space as well as power-to-fuels (natural gas, diesel, SAF), ammonia and methanol, given the challenges of transporting hydrogen.

“If you’re going to produce hydrogen, you need to produce it close to the place where it’s going to be consumed, because transporting it is hard. Or you need to turn it into something else that we already know how to transport – natural gas, renewable diesel, naphtha, ammonia.”

Alexander believes power-to-fuels projects and developers that are focused on smaller, on-site modular low-carbon hydrogen production are some of the most interesting to watch right now. Emitters are starting to realize they can lower their overall carbon footprint, he says, with a relatively small amount of low-carbon fuels and inputs.

“The argument there is to not completely replace an industrial gas supplier but to displace a little bit of it.”

At the same time, the mobility market may take off with help from US government incentives for hydrogen production and the growing realization that EVs might not provide a silver-bullet solution for decarbonizing transport, Alexander adds. However, hydrogen project developers targeting the mobility market are still competing with the cost of diesel, the current “bogey” for the hydrogen heavy mobility space, Alexander says.

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Siemens Energy planning new US electrolyzer capacity

The company is targeting expansion in the U.S. given the favorable policy environment following passage of the Inflation Reduction Act (IRA).

Siemens Energy North America is laying the groundwork for new electrolyzer manufacturing capacity in the United States, President Richard Voorberg said during a panel discussion recently.

Siemens Energy, a global energy technology company, makes an 18 MW PEM electrolyzer, one of the largest in the world, and is targeting expansion in the U.S. given the favorable policy environment following passage of the Inflation Reduction Act (IRA), Voorberg said.

The company is building its first gigawatt factory in Berlin, Germany via a joint venture with France’s Air Liquide. The Berlin factory is expected to produce 1 GW of PEM electrolyzers per year starting in mid-2023.

“As soon as we get that first one up and running… I’ve got a plan already to put a 1,000 MW line in the US,” Voorberg said, speaking during an event at the Delegation of German Industry and Commerce in Washington D.C. last month.

Siemens’ existing manufacturing capacity in the US could expand to accommodate that new line, or the company could look to build an entirely new facility, Voorberg said. He added that the recently passed IRA helps makes the business case to do so.

Following the IRA, customers went from asking for fractions of a megawatt to seeking 2 GW in a single order, Voorberg said. His 18 MW line is now insufficient.

“We’ve got to scale up,” he said. “Scale is everything.”

Voorberg said his company sees hydrogen being used in electricity production around 2035, but mobility can use it now.

The planned move by Siemens underscores the extent to which the IRA legislation has trained the hydrogen industry’s focus on the U.S. Norway-based electrolyzer producer Nel is speeding efforts to expand electrolyzer capacity in the U.S. And Cummins announced last month that it would add electrolyzer production space at its existing facility in Fridley, Minnesota.

Siemens Energy is independent of Siemens AG, having spun off in 2020. The company has about 10,000 employees in the US and roughly 2,000 in Canada.

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Exclusive: Verde Clean Fuels seeking project finance for gas refineries

Publicly listed Verde Clean Fuels plans to seek equity and debt investors for low-carbon gasoline refineries it expects to deploy across the US. We spoke to CEO Ernest Miller about the strategy.

Verde Clean Fuels, a publicly listed developer of clean fuels technology and projects, is planning to seek project debt and equity investors to finance a series of low-carbon gasoline refineries it expects to deploy across the US.

Houston-based Verde, which employs syngas-to-gasoline refining technology, recently announced an agreement with Diamondback Energy to construct a facility in the Permian Basin that will utilize stranded natural gas to produce 3,000 barrels per day of gasoline.

The company is also pursuing a carbon-negative gasoline project on the premises of California Resources’ Net Zero Industrial Park in Bakersfield, California. The California project will produce approximately 500 barrels of RBOB renewable gasoline per day from agricultural waste, while capturing and sequestering around 125,000 tons of CO2 per year.

Verde is capitalized following a private investment in public equity (PIPE) injection of $54m as part of a reverse merger last year, allowing the company to take the Bakersfield and West Texas projects through the FEED phase, CEO Ernest Miller said in an interview.

Underpinning Verde’s business model is the view that gasoline will persist as a transportation fuel for many years to come, and that very few parties are working to decarbonize the gasoline supply chain.

“Between renewable diesel, renewable natural gas, and sustainable aviation fuel, there is very little awareness that renewable gasoline is even a thing,” Miller said. “The addressable market is enormous, and the impact that can be made by taking even a sliver of that market is enormous.”

Miller says that many market participants believe that electric vehicles will solve the emissions problem from road transport.

“The fact is that gasoline has a very, very long runway ahead of it,” he said. “Regardless of the assumptions you want to make about EV penetration, the volume of gasoline that we continue to use for the foreseeable future is huge.”

Verde Clean Fuels demo plant.

Verde’s projects are sized in the 500 – 3,000 barrels per day range, making them a unique player at the smaller end of the production range. The only other companies with similar methanol-to-gas technology are ExxonMobil and Danish-based Topsoe, which operate at a much larger scale, according to Miller.

Miller recognizes that low-carbon, or negative-carbon, gasoline operates within a complex ecosystem, with the California project potentially playing in that state’s LCFS and D3 RIN markets, in addition to the market for gasoline.

“What I would like to see us do is have an offtaker that plays in all three of those products – so if I can go to Shell Trading, or bp, or Vitol, and get one of them to say, ‘here’s a price,’ and they take all of that exposure and optionality,” Miller said, “that allows me to finance the project without having to manage a whole bunch of different commodity exposures and risk.”

Bakersfield 

The Bakersfield project, estimated to cost $235m to build, will utilize 450 tons per day of agricultural waste to produce gasoline, and sequester CO2 via California Resources’ carbon management company, Carbon TerraVault, a joint venture with Brookfield Renewable.

Because of the carbon sequestration, the project will qualify for incentives under 45Q, but since it is producing, in Miller’s words, “deeply carbon-negative gasoline,” most of the value for the project will come from California’s LCFS program.

In order to qualify for LCFS credits, the Bakersfield facility goes through the full GREET modeling process – including transport of feedstock, processing and refining, and transport away from the facility – returning a negative 125 grams equivalent per MJ carbon intensity score for the project, according to Miller.

As for investors, Verde “would like to see both California Resources and Brookfield Renewable in the project, either individually or through the Carbon TerraVault JV,” Miller said.

Verde is also in discussions with a handful of financial players, including infrastructure and pension funds that are looking for bond-like cash flow that a project finance model can provide. The company has also explored the municipal bond market in California, which would bring to bear a favorable capital structure for the project, Miller said.

Verde is not currently working with a project finance advisor, Miller said, noting that they have in-house project finance experience. In Texas, Verde is working with Vinson & Elkins as its law firm; and in California Verde is working with Orrick as counsel.

Gasoline runway

For the Diamondback facility in West Texas, which requires roughly $325m of capex, both Verde and Diamondback will take equity stakes in the project, and Verde will seek to bring in debt financing to fund the rest of the project costs in a non-recourse project finance deal, Miller said.

The Permian project seeks to provide a pathway to monetize stranded gas in the basin by taking advantage of and alleviating its lack of takeaway capacity, which causes gas prices at the Waha Hub in West Texas to trade at a significant discount to the Henry Hub price.

“Diamondback would take the position that any gas that’s getting consumed in the Permian Basin is gas that’s not getting flared in the Permian Basin,” Miller said, thus making the project a emissions-mitigating option. “There will never be enough natural gas takeaway capacity out of the Permian Basin,” he added, noting that driller profiles are only going to get gassier as time goes on.

Diamondback, for example, produces more in the Permian than it can take out via pipeline, therefore “finding a use, a different exposure, for that gas by turning it into gasoline, is of value for them,” Miller said.

“It’s the same dynamic in the Marcellus and Bakken and Uinta – all the pipeline-constrained basins,” he added, alluding to possible future expansion to those basins.

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