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LNG project pulls deepwater port application

An LNG project has withdrawn its application for a deepwater port license off the coast of Louisiana. The environmental impact statement preparation process is also cancelled.

Grand Isle LNG, a proposed LNG liquefaction and export project off the coast of Louisiana, has pulled its application for a deepwater port facility.

The Maritime Administration and the U.S. Coast Guard last week posted a notice saying they have cancelled all actions related to the processing of a license application for the proposed Grand Isle LNG project.

The project, announced last year, proposed to build a crew quarters platform, two gas treatment platforms, two 2.1 million tons per annum-MTPA liquefaction platforms, two loading platforms, one thermal oxidizer platform, and two 155,000 cubic meter storage and offloading vessels, according to a press release.

In the notice, MARAD said that, “The action announced here also includes cancellation of all activities related to the deepwater port application review and preparation of an Environmental Impact Statement that was previously published in the Federal Register on Monday, July 3, 2023. The publication of this notice is in response to the applicant’s decision to withdraw the application.”

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Air Liquide invests in two U.S. RNG units

Air Liquide has commenced construction on two dairy-waste RNG units in Pennsylvania and Michigan.

Air Liquide has commenced construction of two new RNG production units located in Center Township, Pennsylvania, and Holland Township, Michigan, treating waste sourced from dairy farms, according to a press release.

The production units will produce biogas from manure feedstock in an anaerobic digester for a total production capacity of 74 GWh, and return the digested waste for the farms’ needs, promoting circular economy in waste management. Using Air Liquide’s proprietary gas separation membrane technology, the biogas will then be purified into RNG and injected into the natural gas grid.

Air Liquide has developed competencies throughout the whole biomethane value chain, starting with biogas production from waste, to its purification into biomethane to be injected into gas grids or compression/liquefaction with storage and transportation to customers. Air Liquide currently has 26 biomethane operational production units in the world for a yearly production capacity of about 1.8 TWh, according to the news release.

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European Commission clarifies some RFNBO rules

In a new Q&A document, the European Commission has clarified several provisions related to the qualification of renewable fuels, including the use of intermediaries in PPAs, the definition of a bidding zone, and the emissions intensity of synthetic fuels.

An updated Q&A document from the European Commission clarifies several provisions related to the qualification of renewable fuels of non-biological origin (RFNBO) and recycled carbon fuels, in answer to questions raised by fuel producers and certifiers following the adoption of the EU’s delegated acts.

The implementation document released yesterday adds language regarding the use of intermediaries in PPAs, allowing for such parties to represent electricity producers in the delivery of electricity for fuel production. A previous version of the document had left open the possibility that fuels producers would have to contract directly with the electricity producers in order to comply with the RFNBO standards, a particularly burdensome concept where utilities have mandated grid ownership.

“Intermediaries referred to in the RFNBO delegated act may be involved by various means and for various purposes, including as a contracting party,” the document reads. “For example, intermediaries can represent the electricity producers, but it is important that a direct relationship between the electricity producer and the hydrogen producer is maintained.”

The document adds that guarantees of origins (GOs) must be compliant with rules set out elsewhere in the Q&A document as well as in the RFNBO delegated act and Article 19 of RED. 

“The GOs for the PPA need to […] carry the same attributes as the physical installation producing the electricity. This includes e.g. the location of the installation, the age of the installation, and the time of the production.”

The new Q&A document also clarifies the definition of a ‘bidding zone’ for purposes of regional compliance, a concept that could result in a narrower definition than the balancing authority regions defined under US rules, due to nodal and zonal power pricing structures in the US system.

“Certifiers should assess whether at the location of the electrolyser, market regulations applied are similar to the rules set out for bidding zones in Regulation (EU) 2019/943,” the Q&A document reads. “In this context ‘similar’ means that there are rules requiring establishing hourly prices for electricity in a geographical area. If such rules are in place, the geographical area for which the prices are established should be considered as a bidding zone for the purpose of the implementation of the methodology.”

If geographical pricing rules are not in place, the document continues, “certifiers should assess whether the electricity network in the country of production is integrated or whether there are several separated networks. If there are several networks, each network should be considered as a bidding zone for the purpose of the implementation of the methodology.”

Meanwhile, “if the electricity network of the country is integrated and there are no geographically differentiated electricity prices, the whole country may be considered as one bidding zone for the purpose of the implementation of the RFNBO delegated act.”

Furthermore, the document includes an annex on the carbon intensity measurement for use of co-processing to produce synthetic fuels:The GHG methodology sets out a specific rule for calculating the emission intensity of RFNBOs stemming from a process where co-processing is applied. It allows to distinguish in the calculation of the greenhouse gas emissions intensity on a proportional basis of the energetic value of inputs between: (1) the part of the process that is based on the conventional input and (2) the part of the process that is based on renewable fuels of non-biological origin and recycled carbon fuels assuming that the process parts are otherwise identical. 

If for instance a process uses H2, CO, CO2 as well as other energy inputs to produce synthetic fuels and the producer intends to replace 20% of the H2 with H2 qualifying as RFNBO, it would be possible to determine the emission intensity of the produced synthetic fuels assuming a virtual process which uses only 20% of all inputs mentioned above (20% of each input). In this example, all hydrogen qualifying as RFNBO (which is 20% of the total H2 input) would be used in the virtual process, and the other 80% of the hydrogen (all non-RFNBO) would be used in the other process which uses 80% of all inputs. Such process would also yield only 20% of the output, but only the energy share of RFNBO hydrogen in the input would be considered an RFNBO. It would be possible to replace in this virtual process more than one input. Not only RFNBOs but also RCF, biomass, renewable electricity, renewable heat and CO2 (including biogenic) could be used for this purpose. While the use of RCF and biomass would not add to the share of RFNBOs in the output, they could reduce the emission intensity of the output as the entire output of the virtual process would have the same emission intensity. “

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MHI completes test of ammonia single-fuel burner

Mitsubishi Heavy Industry tests confirmed stable combustion, reduced nitrogen oxide emissions compared to coal firing, and complete combustion of the ammonia.

Mitsubishi Heavy Industries, Ltd. (MHI) has successfully completed a combustion test of an ammonia single-fuel burner as part of its development of ammonia utilization technology for thermal power generation boilers. The testing was conducted using combustion test equipment at the Nagasaki District Research & Innovation Center in Nagasaki, according to a news release.

Utilizing a combustion test furnace with fuel consumption of 0.5 tons per hour (t/h), MHI conducted a single-fuel burner test using an ammonia burner, and a high-ratio ammonia co-firing test with coal. In both cases, the tests confirmed stable combustion, reduced nitrogen oxide (NOx) emissions compared to coal firing, and complete combustion of the ammonia.

In addition to its role as an energy carrier allowing efficient transport and storage of hydrogen energy at low cost, ammonia can be used directly as a fuel for thermal power generation, and because it does not emit CO2 during combustion, is expected to contribute to the reduction of greenhouse gas emissions. This combustion test confirmed that the basic structure of the burner simultaneously provides for stable combustion of ammonia and suppression of NOx emissions, passing an important development milestone for practical application of the technology in thermal power generation boilers.

As a next step, MHI plans to conduct a combustion test using an actual size burner in a larger 4t/h combustion test furnace. Based on these results, MHI will then take steps for application of the burner it has developed for thermal power plants in Japan and overseas.

Since fiscal 2021, MHI has been pursuing “development and demonstration of high-ratio ammonia co-firing technology in coal-fired boilers” as part of the Fuel Ammonia Supply Chain Establishment project conducted by the Green Innovation Fund Project of the New Energy and Industrial Technology Development Organization (NEDO). This combustion test is part of that project, and by fiscal 2024, MHI plans to develop burners capable of ammonia single-fuel firing for both circular firing and opposed firing type burners.

The Nagasaki District Research & Innovation Center, where the test was conducted, is located in Nagasaki Carbon Neutral Park, MHI Group’s development base for energy decarbonization technologies that commenced operations in August this year. With the success of this combustion test, MHI is accelerating the development of related technologies for practical application in thermal power generation boilers (Note) in Japan and overseas.

MHI Group will continue to propose new solutions that make use of its many proven technologies, including the use of ammonia, which is one of the most promising solutions for reducing CO2 emissions, and promote the energy transition.

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Exclusive: Hydrogen blank-check deal and capital raise on track

A de-SPAC deal and associated capital raise for a hydrogen technology and project development firm are still on track to close this year, despite this year’s busted SPAC deals and sagging hydrogen public market performance.

H2B2 Technologies is still on track to close a de-SPAC deal and related capital raise before the end of this year, CEO Pedro Pajares said in an interview.

Spain-based H2B2 announced the deal to be acquired by RMG Acquisition Corp. III and go public in a $750m SPAC deal in May. In tandem, Natixis Partners and BCW Securities are acting as co-private placement agents to H2B2 for a capital raise that the company must close as part of the acquisition.

The company said recently in filings that the deal as well as the capital raise would close before the end of 2023, a fact that Pajares reiterated in the interview. He declined to comment further.

Many publicly traded hydrogen companies have dropped significantly in value in recent months, and dropped further on Friday following news from Plug Power that it would need to raise additional capital in the next 12 months to avoid a liquidity crisis.

Meanwhile, there have been 55 busted SPAC deals this year, according to Bloomberg, with Ares Management’s deal for nuclear tech firm X-Energy the latest to not close.


H2BE recently inaugurated SoHyCal, its first facility in Fresno, California, and wants to get the message out to offtakers in California’s Central Valley that it has hydrogen available to sell.

“What we want to show is that H2B2 is the solution for those who are seeking green hydrogen in the Central Valley,” Pajares said.

Phase 1 (one ton per day) of the plant was funded by a grant from the California Clean Energy Commission. Phase 2 (three tons per day) will involve transitioning to solar PV power, and the company could consider a project finance model to finance the expansion, though Pajares believes the market is not yet ready to finance hydrogen projects.

In addition to project development, the company is also an electrolyzer manufacturer. It is focusing its efforts in the California market on future projects that are larger than SoHyCal, as well as those related to individual offtakers, Pajares said. End users will be in mobility and fertilizer, with offtake occurring via long-term contracts as well as through spot market transactions.

The company is pursuing developments in other regions of the US as well, he added, declining to name specific areas.

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EXCLUSIVE: 8 Rivers co-founder departs firm

A co-founder and executive has departed the North Carolina-based firm, which recently announced an ammonia project in Texas.

Bill Brown, a co-founder of the technology commercialization firm and clean fuels developer 8 Rivers Capital, has retired from the company, a spokesperson confirmed via email.
According to Brown’s LinkedIn profile, he is serving now as CEO of New Waters Capital. He co-founded 8 Rivers and also served as CEO and CTO in this nearly 16 years there.
Brown did not respond to a request for comment.
According to 8 Rivers’ website, Dharmesh Patel is serving as interim CEO. The company recently announced development of the Cormorant Clean Energy ammonia production facility in Port Arthur, Texas
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Waste-to-energy company interviewing advisors for strategic capital raise

Vancouver-based Klean Industries plans to run a process to raise between $250m – $500m of capital to deploy into projects, some of which would use green hydrogen to upgrade recovered fuel and pyrolysis oils.

Waste-to-energy specialist Klean Industries is interviewing financial advisors and planning to run a process to find investors for a strategic capital raise.

The Vancouver-based company is seeking to raise between $250m – $500m in a minority stake sale that would value the company around $1bn, Klean CEO Jesse Klinkhamer said in an interview.

Klean had previously intended to list on the NASDAQ exchange but those plans were nixed due to the COVID-19 pandemic, he said. The company still plans to list publicly in 2024 or 2025.

Proceeds from a capital raise now would be used to “rapidly deploy” into the projects that Klean is advancing around the globe, Klinkhamer said.

For one of those projects – a flagship tire pyrolysis plant in Boardman, Oregon – Klean is raising non-recourse debt to finance construction, the executive said. Klinkhammer declined to name the advisor for the project financing but said news would be out soon and added that the company has aligned itself with infrastructure funds willing to provide non-recourse debt for the facility.

The Boardman project, which is expected to cost roughly $135m, is an expansion of an existing site where Klean will use its advanced thermal conversion technology to recover fuel oil, steel, and refined carbon black from recycled tires. The end products are comparable to virgin commodities with the exception of being more cost-effective with a lower carbon footprint.

“A lot of what we do is of paramount interest to a lot of the ESG-focused infrastructure investors that are focused on assets that tick all the boxes,” Klinkhamer said, noting the consistent output of the waste-to-energy plants that Klean is building along with predictable prices for energy sourced from renewable power.

Klean has also partnered with H2Core Systems, a maker of containerized green hydrogen production plants, and Enapter, an electrolyzer manufacturer. The company will install a 1 MW electrolyzer unit at the Boardman facility, with the green hydrogen used to upgrade recovered fuel oil and pyrolysis oil into e-fuels that meet California’s Low Carbon Fuels Standards.

“We were exploring how we could improve the quality of the tire pyrolysis oil so that it could enter the LCFS market in California,” he said, “because there are significant carbon credits and tax incentives associated with the improved product.”

The company received proposals from industrial gas companies to bring hydrogen to the Boardman facility that were not feasible, and Klean opted for producing electrolytic hydrogen on site in part due to the abundance of low-cost hydroelectric power and water from the nearby Columbia River.

Addressable market

Discussing Klean’s addressable market for waste-to-energy projects, Klinkhamer points to Japan as an example of a comparable “mature” market.

Japan, an island nation of 126 million people, has built roughly 5,000 resource recovery, waste-to-energy plants of various scopes and designations, he notes. For comparison, the United Kingdom – another island nation of 67 million people – has just 20 waste-to-energy plants.

“The opportunity for waste-to-energy in the UK alone is mind boggling,” he said. “There are a thousand opportunities of scope and scale. Nevermind you’ve got an aging, outdated electrical infrastructure, limited landfills, landfill taxes rising – a tsunami of issues, plus the ESG advent.”

A similar opportunity exists in North America, he noted, where there are around 100 waste-to-energy plants for 580 million people. The company is working on additional tire, plastic, and waste-to-energy projects in North America, and also has projects in Australia and Europe.

Hydrogen could be the key to advancing more projects: waste-to-energy plants have typically been hamstrung by a reliance on large utilities to convert energy generated from waste into electricity, which is in turn dependent on transmission. But the plants could instead produce hydrogen, which can be more easily and cost effectively distributed, Klinkhamer said.

“There is now an opportunity to build these same plants, but rather than rely on the electrical side of things where you’re dealing with a utility, to convert that energy into hydrogen and distribute it to the marketplace,” he added.

Hydrogen infrastructure

Klinkhamer says the company is also examining options for participating in a network of companies that could transform the logistics for bringing feedstock to the Boardman facility and taking away the resulting products.

The company has engaged in talks with long-haul truckers as well as refining companies and industrial gas providers about creating a network of hydrogen hubs – akin to a “Tesla network” – that would support transportation logistics.

“It made sense for us to look at opportunities for moving our feedstock via hydrogen-powered vehicles, and also have refueling stations and hydrogen production plants that we build in North America,” he said.

Klean would need seven to 12 different hubs to supply its transportation network, Klinkhamer estimates, while the $350m price tag for the infrastructure stems from the geographic reach of the hubs as well as the sheer volume of hydrogen required for fueling needs.

“With the Inflation Reduction Act, the U.S. has set itself up to be the lowest-cost producer of hydrogen in the world, which will really spur the development of hydrogen logistics for getting hydrogen out,” he said. “And to get to scale, it’s going to require some big investments.”

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