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SoCalGas and Bloom Energy powering Caltech with hydrogen project

The project will inject hydrogen into natural gas infrastructure and be converted into electricity using fuel cells.

Southern California Gas Company and Bloom Energy will power a portion of Caltech’s grid with an innovative hydrogen project that demonstrates how hydrogen could potentially offer a strong solution for long-duration clean energy storage and dispatchable power generation, according to a news release.

This project takes water from Caltech’s service line and runs it through Bloom Energy’s solid oxide electrolyzer, which uses grid energy to create hydrogen. The resulting hydrogen is injected into Caltech’s natural gas infrastructure upstream of Bloom Energy fuel cells, creating up to a 20% blend of hydrogen and natural gas. All of this fuel blend is then converted into electricity with Bloom Energy’s fuel cells, and the electricity is then distributed for use on campus.

Blending hydrogen into natural gas infrastructure statewide – which could help reduce dependence on fossil fuels and ultimately drive down hydrogen costs by scaling production – first requires developing a hydrogen injection standard. The global hydrogen economy is projected to potentially produce as much as 80 gigatons of carbon abatement by 2050, which represents approximately 11% of required cumulative emissions reductions.

SoCalGas is working to help develop a state hydrogen blending standard by proposing pilot projects for approval by the CPUC. These projects could help to better understand how clean fuels like clean renewable hydrogen could be delivered through California’s natural gas system.

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How the Siemens Gamesa meltdown shapes the emerging electrolyzer market

The near-collapse of Siemens Energy in part due to the performance of its wind turbine unit, Siemens Gamesa, is informing contract developments in the emerging market for electrolyzer technology.

Siemens Energy in November reached a deal for performance guarantees backstopped by the German government and major banks after issues emerged with two of its wind turbine offerings, putting the company on the hook for nearly $5bn in added costs.

The financial wobbles have focused attention not just on the underlying technical glitches in the turbines, but also on the performance guarantees that Siemens Gamesa has provided in support of the operations of those turbines. 

Performance guarantees from technology suppliers ensure the quality of equipment at installation and through the life of a generation facility. Such guarantees from electrolyzer manufacturers have become a formidable sticking point in negotiations for supply contracts and the associated green hydrogen project finance deals.

“The lender at the project level needs the technology vendor to take technology and operational risk for 10 years,” Strata Clean Energy’s Mike Grunow said in an interview last month, referring to a series of agreements that must be in place in order for green hydrogen projects to reach financial close.

Market dynamics are currently working in favor of the electrolyzer makers, where a rush to build projects has created a supplier’s market, allowing the electrolyzer OEMs to hold back more favorable terms from project owners relating to liquidated damages and performance guarantees.

But the harsh spotlight on the issue at Siemens Gamesa is also informing the stance of electrolyzer OEMs.

Siemens Energy, itself, is working through onerous performance guarantees in the wind business while avoiding granting those same types of guarantees in other areas of its business, including electrolyzers.

‘The T&C’s situation’

In an investor presentation last month, executives from Siemens Gamesa noted their strategy to revamp the terms and conditions for the guarantees they are granting in the wind business, referring to the problem as “the T&Cs situation.”

“We have been extremely generous in the past to accept terms and conditions which, going forward, may hit us,” Jochen Eickholt, Siemens Gamesa’s CEO, said. “We are by far away from what should be the standard terms and conditions.”

In the green hydrogen industry, the lack of sufficient guarantees has held up supply contracts as well as project finance negotiations, as lenders, sponsors, and EPC firms are unwilling to take on the risks of underperformance from emerging electrolyzer technologies, experts said.

The NEOM green hydrogen project in Saudi Arabia, which reached financial close in May, is often referred to as a market precedent for similar projects. But the project had unique characteristics that will be difficult to emulate: Air Products, for one, served as sponsor, EPC contractor, and offtaker, eliminating the usual cross-party risk-sharing dynamics. 

Even so, opportunities for electrolyzer performance to deviate significantly from proven operating results is “pretty small,” according to James Bowe, a partner at King & Spalding, a law firm that advised on the NEOM project. As such, electrolyzer performance is less of an issue as it would be with rotating equipment or solar PV cells. 

Additionally, project proponents and their electrolyzer partners are finding creative ways to overcome the lack of performance guarantees. 

“The way you can overcome it is just put in another electrolyzer, because the fundamental question is ‘are you getting enough gas out to supply your requirements?’ You can do that either by adding another electrolyzer or turning up the power,” Bowe added.

He noted, for example, that green hydrogen developers can set up something of an escrow scheme, where the first shipment of green hydrogen includes extra units, which would sit for a certain delivery period in case the supply of hydrogen comes up short.

King & Spalding was recently on the verge of concluding a supply agreement with one electrolyzer manufacturer that will include a performance guarantee or performance shortfall remediation scheme, as well as a provision addressing delays, Bowe said. 

“Given this, there seems to be some hope that at least some manufacturers will agree to performance and schedule guarantees of some sort,” he added. “But this was a hard fought battle.”

Electrolyzer OEMs are having to come up the learning curve from garage industry to large-scale infrastructure projects with project financing literally overnight, said Fred Lazell, an associate on King & Spalding’s energy team in London.

These companies “know it’s a supplier’s market,” Lazell said. “The instructions they’re receiving from senior management are ‘don’t give away the family jewels too early in the game.’ They see experiences from other technologies like offshore wind and solar, where the OEMs gave up early on in the expansion of the industry quite favorable performance regimes, and that had a big impact on those industries.”

Indeed, warranties for wind turbines have been a systemic issue for the industry, with Vestas, GE, and others having their profitability sapped in recent years.

EPC margins

The reticence of electrolyzer OEMs to provide robust performance guarantees stems from legitimate technical questions: there has never been this scale of operations and related offtake and financing commitments tied to electrolyzer technology. 

But the electrolyzer OEMs are also positioning themselves commercially, according to Lazell. “And the only way we see to get around this is through a partnership between the project owner and the OEM.”

Lazell noted that EPC contractors will provide a “wrap” – turnkey EPC agreements providing for engineering, procurement, construction, commissioning and testing of a project – but pass through the guarantees they get from the electrolyzer provider, nothing more.

Moreover, the margins required by EPC contractors to provide a wrap for the electrolyzer technology would likely blow up project economics.

“That’s why it’s so important to have that direct relationship with the electrolyzer supplier, so the owner can get the best deal possible,” he said. “Because ultimately the project owner is paying for the OEMs’ plant expansion to meet that demand and future demand,” he added, referring to the many electrolyzer providers that are planning to build new production capacity.

To mitigate the cost of an EPC wrap, a project can first put in place credit support from the technology provider, which then gets wrapped through the EPC contract, bringing down the cost of the EPC contract.

While credit support mechanisms will likely be required for many of the smaller, start-up electrolyzer makers, creditworthiness of the OEM is still an issue for the larger companies – like Siemens Energy.

S&P moved in July to downgrade Siemens Energy’s long-term credit rating to BBB-, one step above junk status.

“Although size usually matters, it doesn’t make the creditworthiness problem go away,” Bowe said. 

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Florida liquefaction and storage firm raising $125m

A Florida-based hydrogen liquefaction and storage provider is in the middle of a Series A capital raise and has identified a financial advisor for a larger Series B.

GenH2, a manufacturer and installer of hydrogen liquefaction and liquid hydrogen storage systems, is undergoing a $25m Series A raise and has plans to conduct a Series B within 12 months, CEO Greg Gosnell said in an interview.

Young America Capital is advising GenH2 on the Series A, Gosnell said. Two term sheets from lead investors are expected this week for the Series A, he added.

B Riley will likely be conducting the Series B, which will seek to raise about $100m. The company has raised approximately $24m from four seed investors in the last two-and-a-half years.

Gosnell projects the company will generate $10.8m in revenues this year, with a “hockey stick” of revenue growth coming in the next two years. The company’s first one-ton-per-day liquefaction and controlled storage solution will roll out at the end of 2Q24. It will have a 5,600 sq ft. footprint.

The company has a partnership with Chart Industries to collaborate on global sales and marketing opportunities, equipment manufacturing and supply, and the deployment of GenH2’s one-ton-per-day liquefier.

Use of funds from the capital raises will predominantly go toward purchasing components and buildout and expansion of manufacturing facilities, Gosnell said. The company has a 35,000 sq. ft. manufacturing facility adjacent to its headquarters in Titusville, Florida, and is considering another location in Texas or Louisiana.

Currently the company, with 46 employees, has closed three contracts on one-ton-per-day liquefaction and storage systems, each between $10m and $12m, Gosnell said. Two additional sales have been made in Australia and Canada for 20-kilogram liquefaction solutions, each $2.2m with credit-worthy customers.

Facilities capacity in Titusville will probably be filled next year. There is space in Titusville to expand more than 100% and the company will option leases for manufacturing.

Going forward the company is interested in strategic partners, Gosnell said. A lot of VC-type investors want to deploy capital in the space but the difficulty is finding an investor confident enough to do the technology due diligence and take the lead.

Easier with liquid

GenH2 installs closed-loop helium-cooled systems of between one and five tons at ports, manufacturing and trucking facilities. The process is done with no liquid nitrogen (LN2), which eliminates the need for truckloads of LN2 or an adjacent LN2 plant.

“Everywhere you see a liquid hydrogen plant today, there’s an LN2 plant next door that’s about five times bigger,” Gosnell said.

GenH2’s liquid hydrogen storage capabilities were demonstrated with NASA, transferring the liquid from multiple tanks with zero loss, he said.

Liquid hydrogen is more energy-dense than compressed gas, bringing down the cost of transportation. In many cases, liquid hydrogen can be dispensed into compressed gas.

“It seems counterintuitive, but if you’re sitting there storing compressed gas at say 100 psi and you need to get to 900 [psi], that’s a lot of work,” Gosnell said. “That’s heavy-duty compression and probably a two-ton chiller.”

Conversely liquid hydrogen wants to become gas, requiring only that you let it vaporize into a smaller tank and it compresses, he said.

“You don’t need any of that work,” he said. “Believe it or not it’s easier to get to a seven or nine-hundred PSI gas with liquid hydrogen than it is from gaseous hydrogen.”

GenH2 is competing against liquid hydrogen delivered in a truck, Gosnell said. He doesn’t know of anyone else doing standalone refrigerated storage with zero transfer loss.

Efficiency is a core focus in design, Gosnell said. Levelized cost with capex and opex all in is between $3 and $3.50 per kilogram for liquifying and storing. With electrolysis or other H2 sourcing on the front end, the company is at $7 or $8 a kilogram, which will improve as renewables are applied.

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PE-backed biomass-to-energy operator on the block

A biomass-to-energy firm with four operational assets in the US and Canada has launched a sale process. The company is also developing 110 MW of co-located BESS projects, with additional revenue streams expected from organic waste diversion, gasification and carbon capture, and heavy-duty vehicle charging stations, according to a sale teaser.

Biomass-to-energy firm Greenleaf Power is for sale.

Denham Capital, the company’s private equity owner, has mandated BNP Paribas to run the process, which launched last week, according to two sources familiar with the process.

California-based Greenleaf is a biomass generation platform with 135.5 MW of fully-contracted renewable generation capacity and remaining weighted-average PPA term length of 9.5 years, according to a sale teaser.

The company’s four operational assets are the 45 MW Desert View Power, in Mecca, California; the 30 MW Honey Lake Power in Wendel, CA; the 23 MW St Felicien Cogeneration facility in Quebec; and the 37.5 MW Plainfield plant in Connecticut.

Greenleaf expects to generate $106m of biomass revenues in 2024, resulting in $24m in expected EBITDA.

According to the teaser, co-located battery energy storage projects amounting to 110 MW are also under development, with CODs expected for 2025 – 2026.

There is potential for additional revenue streams from existing infrastructure and land, including organic waste diversion, gasification and carbon capture, co-location of renewables, and heavy-duty electric vehicle charging stations, the teaser states.

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Exclusive: Carbon conversion startup planning capital raise

A Halliburton Labs-backed startup is developing a pilot plant in the Pacific Northwestern US, while forming financial relationships for an industrial-scale carbon conversion facility in the same location.

OCOchem, a Washington state-based carbon conversion startup, will seek new capital partners to build its first commercial scale facility in 2026, CEO Todd Brix said in an interview.

Starting in late 2024 or early 2025, the company will likely go to market for new liquidity – including project debt and equity, Brix said. He declined to talk about capex, but said the first commercial plant in Richland, Washington will cost “multiple tens of millions of dollars.”

The company is working with two EPCs now and is represented legally by Miller Nash law firm in the Pacific Northwest, Brix said. The company does not have a formal relationship with an investment bank but will likely form one for a Series A and later rounds.

“We’ve been in touch with a number of private equity and project finance people,” Brix said of early-stage discussions.

OCOchem is considering land options in Richland for its first plant and is organizing to begin permitting, Brix said. There is opportunity to form relationships with industrial partners in need of an offtaker for their CO2 emissions and new incremental revenue streams, as well as customers for chloral hydrates and other formic acid products.

“We expect to build hundreds of these plants all around the planet,” Brix said, referring to the process of electrochemically converting emitted CO2 and water to formic acid, which can then be used to make a suite of products like hydrogen, carbon monoxide, and formate (methanoate) derivatives. “We are close to industrial size on our plants right now.”

CO2 is captured from steam methane reformers, natural gas processing and piping, and ammonia production, among other processes. The gas is then combined with water in a cellular, modular process producing formic acid, derivatives of which can be used in a range of industries like pharmaceuticals.

The company recently raised $5m in seed funding from lead investor TO VC, which joined backers LCY Lee Family Office, MIH Capital Management, and Halliburton Labs. An additional $8m has been raised in grant funding from the US departments of Energy (DOE) and Defense (DOD).

The company is also partnered with the Nutrien Corporation on a small scale facility in Kennewick, Washington, just upriver from Richland, Brix said. Financing for that project is largely arranged with the FEED completed.

Brix owns a majority of the company with his father.

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exclusive

Former Denbury executive targeting growth through CCS at industrial emitters

Tracy Evans, a former COO of Denbury Resources, has launched a business unit aimed at offering carbon capture and sequestration services for existing industrial emitters.

CapturePoint, a Texas-based carbon capture and enhanced oil recovery specialist, is seeking to grow by offering carbon capture services to existing industrial emitters.

The company, started with an initial focus on enhanced oil recovery operations using CO2, has launched a subsidiary called CapturePoint Solutions to capitalize on growing demand for carbon capture services at industrial plants, CEO Tracy Evans said in an interview.

Evans, a former chief operating officer of Denbury Resources, has years of experience operating CO2 capture units, pipelines, and oil wells. “The only difference between EOR utilization and sequestration is going to the saline aquifers,” he said of the pivot.

The company’s primary focus is on existing emissions, Evans said, emphasizing the immediate opportunity over proposed plants that might take many years to build. He added that the company would target “pure” sources of CO2 versus diluted sources.

Evans brought in a JV equity partner for the CCS business, but declined to name them. He said the company is sufficiently capitalized for now but might need to raise additional equity as it signs up new projects in the next 12 to 16 months.

Tax equity and CCS

CapturePoint recently completed a tax equity deal for a CCS facility that has been operational since 2013, thanks to changes to provisions governing the use of 45Q for carbon capture that allowed existing plants to qualify if they capture over 500,000 tons of CO2.

The deal, at CVR Partners’ Coffeyville fertilizer plant, opened up an initial payment of $18m and includes installment payments, payable quarterly until March 31, 2030, totaling up to approximately $22m.

An ethanol facility where CapturePoint operates will also qualify for 45Q benefits because 80% or more of the carbon capture unit is being rebuilt, Evans said. The company was able to finance the new construction at the ethanol facility from cash flow out of its oil & gas operations.

Going forward, new projects installed at existing emitters will follow a project finance model, with equity, debt, and 45Q investors, Evans said. The company will use a financial advisor when the time is right, the executive noted, but said there’s more work to be done on sizing and costs before an advisor is lined up.

“The capture costs are similar for each site,” he said. “The pipeline distances to a sequestration site is what drives significant variation in total capital costs.”

Evans believes that tax credit increases in the Inflation Reduction Act – from $35 per ton to $60 per ton for CO2 used in EOR, and $50 per ton to $85 for CO2 sequestration – should help the CCS market evolve and lead to additional deals.

“There wasn’t much in it for the emitter at $35 and $50, to be honest,” he said, “whereas at $60 and $85 there’s something in it for the emitter.”

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Exclusive: Biomethane firm planning funding round

A biomethane solutions provider with projects in Europe and the US is planning a fifth round of funding to launch early next year, with a need to raise additional project debt.

Electrochaea, the US- and Europe-based biomethane developer, will go to market in 1Q24 for a new round of equity funding, with a near term need for project debt as well, two executives told ReSource.

The company, which was spun out from an incubator at The University of Chicago with offices in Denmark, has projects in Denmark, Colorado, New York and Switzerland. It is backed by Baker Hughes and, from early fundraising efforts, Munich Venture Partners, senior director Aafko Scheringa said. The former investor participated in its most recent (fourth) $40m funding round.

Electrochaea uses a patented biocatalyst that converts green hydrogen and carbon dioxide into BioCat Methane, a pipeline-grade renewable gas.

The average size of a project is roughly $25m, Scheringa said.

Funds from the next round will provide three years of working capital, CEO Mitch Hein added.

Electrochaea has not worked with a financial advisor to date, Hein said, adding that he may have need for one for new processes but has not engaged with anyone.

Scheringa said he is working to achieve commercialization on a pipeline of projects, with a 10 MWe bio-methanation plant in Denmark being farthest along with a mandatory start date before 2026.

Electrochaea has a bio-methanation reactor system in partnership with SoCalGas at the US Department of Energy’s National Renewable Energy Laboratory (NREL) Energy System Integration Facility in Golden, Colorado, though Hein said a project in New York is as advanced in its development.

Bio-methane can be burned in place of natural gas with no systems degradation issues, so gas offtakers are a natural fit for Electrochaea, Scheringa said. Cheap clean electricity paired with available CO2 is critical, so the company will look to places like Texas, Spain, Scandinavia, Quebec and the “corn states” of the US Midwest, for new projects.

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