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Exclusive: E-fuels developer raising $500m

A developer of green hydrogen for e-fuel products is looking for a more diverse set of backers for a recently launched Series C capital raise.

Ineratec, the German power-to-liquid fuels developer and technology provider, has launched a $500m Series C and could take on a US-based financial advisor to help, CEO Tim Boeltken said in an interview.

German boutique Pava Partners helped Ineratec on its $129m Series B, which was led by Piva Capital. The Series B raise, which was announced in January, also included participation from HG Ventures, TDK Ventures, Copec WIND Ventures, RockCreek, Emerald, Samsung Ventures as well as the increased support from current investors, including global corporates like ENGIE New Ventures, Safran Corporate Ventures and Honda.

The Series C can include equity, debt and project finance, Boeltken said.

The company, which takes a modular approach to fuels production, serves customers in Switzerland, Spain and Finland. Its e-fuels process involves two main steps: first, turning CO2 and hydrogen into synthesis gas, then using a second reactor to turn the synthesis gas into liquid and solid hydrocarbons, according to its website.

Growth in the US would include eventual rollout of its 100 MW commercial unit, none of which have been built to date. Now the company is focused on its 10 MW commercial units, following completion of a 1 MW industrial plant operating now.

In the next month Ineratec will be scouting locations in the US, Boeltken said, adding the the company is “hoping for many, many US installations” with eyes on additional applications in South America and Japan. The company also intends to establish a US headquarters.

Sites in New York and California are of first interest but there are also growth intentions in Texas, Washington state and Appalachia.

Ineratec is currently raising project finance for a “triple-digit” million capex project in the Europe, he said.

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Shearman’s Dajani moves to Baker Botts

Mona Dajani has moved to law firm Baker Botts after less than a year at Shearman & Sterling.

Baker Botts has brought on Mona Dajani as a partner in its New York office.

She will become global co-chair of energy infrastructure and hydrogen and co-chair of the firm’s energy sector, according to a news release.

Dajani joined Shearman & Sterling in February of this year, following four years at Pillsbury.

Her global practice has involved representation of some of the largest blue-chip clients worldwide, according to the release. In her over 20 years of practice, she has led numerous energy, sustainability, and infrastructure deals, including on complex mergers and acquisitions/dispositions, project development, financings, joint ventures, restructuring, tax equity and tax credit financings involving energy and related infrastructure facilities in the U.S. and around the world.

The transactions she has led involve solar, wind, hydrogen, hydroelectric and geothermal, as well as ammonia, mobility, various energy deals with data centers, electric vehicles, carbon capture and sequestration, renewable natural gas, biofuels, net-zero technology and other energy transition projects.

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New renewable diesel plant transacts at $499m

Camber Energy, a NYSE-traded energy company, has reached a deal to acquire 100% of the interests in New Rise Renewables, the owner of a newly developed renewable diesel plant in Reno, Nevada.

Camber Energy, a NYSE-traded energy company, has reached a deal to acquire 100% of the interests in New Rise Renewables, the owner of a newly developed renewable diesel plant in Reno, Nevada.

The plant, which will produce 43,000,000 gallons per year (5,971,585 MMBTUs) of renewable diesel from triglyceride oils such as corn, was purchased for $499m, representing a purchase price of $750m less $251m of existing company liabilities, according to a securities filing. The seller is RESC Renewables Holdings, a predecessor company to Ryze Renewables, which developed the project.

The renewable diesel produced by New Rise Renewables Reno is completely interchangeable with diesel derived from petroleum and can efficiently power diesel engines, such as semi-trucks and large-scale emergency generators. Phillips 66 is under contract to supply all of the feedstock for New Rise Renewables Reno and will purchase 100% of the renewable diesel product for use and sale nearby in California.

The parties had reached a framework for the deal in late 2021, subject to purchase price adjustments and other closing conditions.

Reno-based Greater Commercial Lending (GCL) facilitated $112.6m in government-guaranteed credit for the development of New Rise Renewables Reno. Eighty percent of the GCL-arranged financing for New Rise Renewables Reno is guaranteed by the United States Department of Agriculture (USDA) via its 9003 Biorefinery, Renewable Chemical and Biodiesel Production Manufacturing Assistance Program. The financing structure includes participation by GCL parent Greater Nevada Credit Union, other credit unions, insurance companies and secondary market groups.

Renewable diesel is made by causing chemical reactions through the addition of hydrogen to the natural fats and oils. New Rise has deployed proven state-of-the-art efficient and cost-effective technology methods, which involves hydrogenating the triglycerides, according to an August news release. The process uses hydrogen, pressure, catalyst and heat in an efficient manner, allowing reactions to be uniform and controlled – increasing yield, lowering operating costs and allowing for feedstock flexibility.

The fuel plant is located in the Tahoe-Reno Industrial Center, the largest industrial park in the world. Other occupants include Tesla, Walmart, Google, FedEx, Switch and Panasonic.

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Aurora Hydrogen raises $10m Series A for zero-emission gray hydrogen

The hydrogen production technology developer has raised $10m in Series A funding led by Energy Innovation Capital.

Aurora Hydrogen, a company developing emission-free, hydrogen production technology, has raised $10m in Series A funding led by Energy Innovation Capital. Participating investors include Williams, Shell Ventures, Chevron Technology Ventures and the George Kaiser Family Foundation.

The funding adds to additional funding by the Natural Sciences and Engineering Research Council of Canada (NSERC) that the team received earlier this year.

Aurora Hydrogen is scaling their proprietary and highly efficient microwave pyrolysis technology to produce hydrogen and solid carbon without generating CO2 emissions or consuming water, according to a press release. Aurora’s technology is highly scalable, with units that can supply a broad range of applications from distributed fueling to hydrogen injection and industrial processes.

Hydrogen production from the Aurora technology has the potential to significantly reduce global CO2 emissions by over 900 million tonnes per year. Additionally, Aurora uses 80% less electricity than electrolysis, the conventional method of producing clean hydrogen, requiring far less electrical generation capacity per kg of hydrogen. And, unlike electrolysis, the process does not require water as a feedstock, preserving another critical and scarce resource.

“At Aurora, we are producing low-cost hydrogen at the point of use, at the exact scale required, and without generating any CO2,” said Andrew Gillis, CEO, Aurora Hydrogen. “We use existing energy pipelines and distribution systems to move the energy, then produce hydrogen where it’s needed, eliminating the need for any new costly hydrogen transportation infrastructure.”

The recent funding will be used to build and operate a 200 kg-H2/day demonstration plant for field trials in Edmonton, Canada. Current hydrogen production is either expensive and distributed or low-cost and centralized, requiring additional costs to transport. Aurora’s technology has the potential to unlock many new hydrogen markets and applications by providing low-cost hydrogen at the point of use, fast-tracking the path to decarbonization in heavy transportation, residential and commercial heating, and many industrial processes.

“Energy Innovation Capital invests in innovative companies commercializing technology for clean, abundant and affordable energy for all,” said Christopher Smith, managing director, Energy Innovation Capital. “Aurora’s novel and thermodynamically sound approach has the opportunity to decarbonize the current carbon intensive hydrogen industry and lead the commercialization of new low-carbon hydrogen applications.”

Aurora Hydrogen’s founding team is made up of Andrew Gillis, PhD, MBA, P.Eng, Erin Bobicki, PhD, P.Eng, and Murray Thomson, PhD, P.Eng.

Williams made its investment through its Corporate Venture Capital (CVC) program, which is intended to support efforts to commercialize emerging technologies including clean hydrogen, solar, carbon capture utilization and storage (CCUS) and next generation natural gas, according to a separate release.

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AGDC seeks $150m in development capital for Alaska LNG project

The Alaska corporation is raising capital to reach FID on a $44bn LNG project that includes the construction of a natural gas pipeline and carbon capture infrastructure.

The Alaska Gasline Development Corporation (AGDC) is actively working to raise $150m in development capital for the Alaska LNG project, with Goldman Sachs providing advisory services.

This capital will cover third-party Front End Engineering Design (FEED) costs, project management, legal and commercial expenses, and overhead for 8 Star Alaska, the entity overseeing the project. Investors will receive a majority interest in both 8 Star Alaska and Alaska LNG as part of the fundraising efforts, according to a presentation​​.

AGDC, a public corporation of the state of Alaska, is hoping to finalize a deal for development capital in the next 12 months, but has not set a definitive timeline for the fundraise, AGDC’s Tim Fitzpatrick said.

The total cost of the project is estimated at $44bn, according to Fitzpatrick, and consists of three principal infrastructural components:

  1. Arctic Carbon Capture (ACC) Plant: Located in Prudhoe Bay on Alaska’s North Slope, this plant is designed to remove carbon dioxide and hydrogen sulfide before natural gas enters the pipeline.
  2. Natural Gas Pipeline: This 807-mile pipeline, with a 42-inch diameter, connects the ACC plant to the LNG facility and is capable of transporting 3.7 billion ft³/d of natural gas. It includes multiple offtake points for in-state residential, commercial, and industrial use.
  3. Alaska LNG Facility: Situated at tidewater in Nikiski, Alaska, this facility features three liquefaction trains, two loading berths, two 240,000 m³ LNG tanks, and a jetty. It is designed to produce 20 million tons per year of LNG​​.

Strategies to raise the necessary funds include collaborating with established LNG developers, strategic and financial investors, and possibly forming a consortium, according to the presentation. All project equity will flow through 8 Star Alaska, keeping the legal and commercial structure of the project consistent​​.

As of last year, the corporation was negotiating sales agreements for a significant portion of the Alaska LNG project’s capacity. Discussions include contracts covering 8 million tonnes per annum (MTPA) at fixed prices and market-linked charges, and equity offtake talks for up to 12 MTPA. Additionally, three traditional Asian utility customers have shown interest in a minimum of 3 MTPA, potentially increasing to 5 MTPA.

These negotiations involve traditional Asian utility buyers, LNG traders, and oil and gas companies, all credit-worthy and large-scale market participants, the company said. Some buyers are contemplating equity offtake, investing at the Final Investment Decision (FID) in exchange for LNG supplied at cost​​.

A key component of the project’s advancement is securing gas supply agreement terms, identified as a prerequisite by multiple investors. AGDC has held meetings with executives from two major producers to emphasize the need for Gas Supply Precedent Agreements to attract further investment. These discussions, highlighting the project’s importance to Alaska, were joined by key figures including the DOR Commissioner Crum, the DNR Commissioner Boyle, and representatives from Goldman Sachs​​.

The Japan Energy Summit, sponsored by AGDC, focused on the need for new LNG capacity in Asia. Japan’s Ministry of Economy Trade & Industry (METI) expressed strong support for new LNG investments and offtake, emphasizing the replacement of coal with gas in developing Asian markets​​.

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Exclusive: Biofuels developer interviewing bankers for capital raise

The developer of a renewable diesel and SAF plant in East Texas is seeking a banker for assistance raising development and FID capital.

Santa Maria Renewable Resources, a biofuels developer with a project in East Texas, is interviewing bankers for an upcoming capital raise.

The Houston-based firm is seeking a banker to help it raise some $40m in development capital, in a role that would then pivot to arranging project finance for a final investment decision, CEO Pat Sanchez said in an interview.

The company recently announced its selection of Topsoe as technology provider for the 3,000-barrels-per-day facility, which will produce renewable diesel and sustainable aviation fuel. It also tapped Chemex to conduct the FEED study.

Sanchez is the former COO of Sanchez Midstream Partners, having left in 2020 after preferred shareholder Stonepeak took over the company.

He perceives headwinds for capital raising in the biofuels space, but believes the project profile he is promoting is superior to peers due to its hedged profile and the incorporation of a sustainable agriculture component that extracts additional value from an oilseed.

The superior returns, which he claims are north of 25% on an unlevered basis, “come from the integration of two industries” – biofuels and agricultural commodities – “on one site.”

Using Topsoe technology, the proposed plant can swing between 100% SAF to 100% renewable diesel, depending on the needs of the offtaker.

The project has an agreed-upon term sheet for offtake with an oil major. Under the agreement, the oil major is required to deliver feedstock in the form of camelina, canola, and soybean, he said.

Only one company in the U.S. closed on a development capital raise for a bio-based fuel project in 2023. That company was DG Fuels, and it raised up to $30m in development capital for a woody biomass-based Louisiana SAF plant expected to cost $4.2bn and reach FID in 2024.

“There seems to still be some headwinds in some companies on the biofuels side that are struggling to raise development capital,” Sanchez said, noting that the biofuels and clean energy sectors were some of the worst performers in 2023.

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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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