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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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JERA commences ammonia co-firing tests

JERA and IHI will seek to establish technology for the use of fuel ammonia in thermal power generation with a view toward mainstreaming in society by March 2025.

JERA Co. and IHI Corporation today began a demonstration of large-volume fuel ammonia substitution at a commercial coal-fired thermal power plant.

The testing will be carried out at JERA’s Hekinan Thermal Power Station in Hekinan City through June 2024.

Since October 2022, JERA and IHI have been moving forward in constructing the burners, tank, vaporizer, piping, and other facilities necessary for demonstration testing fuel ammonia substitution at JERA’s Hekinan Thermal Power Station.

IHI has developed a test burner based on the results of small-volume testing of fuel ammonia at the power station’s Unit 5, and JERA has prepared safety measures and an operational framework for the use of fuel ammonia at the power station.

With such preparations in place, the demonstration testing of large-volume fuel ammonia substitution began today at the power station’s Unit 4. The demonstration testing will look at characteristics of the plant overall, investigating nitrogen oxide (NOx) emissions and confirming factors such as operability and the impact on boilers and ancillary equipment.

JERA and IHI, by addressing issues raised through the demonstration testing, will seek to establish technology for the use of fuel ammonia in thermal power generation with a view toward mainstreaming in society by March 2025, according to a news release.

Based on the current demonstration testing, JERA will begin commercial operation of large-volume fuel ammonia substitution (20% of heating value) at Unit 4 of JERA’s Hekinan Thermal Power Station. By establishing the technology for ammonia substitution, JERA will offer a clean energy supply platform that combines renewable energy with low-carbon thermal power, contributing to the healthy growth and development of Asia and the world.

In addition to steadily carrying out the current demonstration testing, IHI will apply the knowledges gained through the Project to establish technology for high-ratio combustion of 50% ammonia or more at thermal power plants and to develop burners for 100% ammonia combustion, deploying the results of the demonstration testing to other thermal power plants in Japan and overseas will contribute to global decarbonization through fuel ammonia.

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Pembina and Marubeni developing Canada-to-Japan blue ammonia project

The project will be structured as an infrastructure-style, fee-based business with investment grade counterparties and is seen as an anchor to a proposed 2,000-acre clean fuels industrial complex in Alberta.

Pembina Pipeline Corporation and Marubeni Corporation have signed an MOU to develop a blue ammonia supply chain from Western Canada to Japan and other Asian markets, according to a news release.

The facility will be on Pembina-owned lands adjacent to its Redwater Complex in the Alberta Industrial Heartland near Fort Saskatchewan, Alberta.

Initial feasibility studies have been completed and the facility has an anticipated design capacity of up to 185 kilotonnes per year of hydrogen production, which will be converted into approximately one million tonnes per year of ammonia.

The facility will include carbon capture with the potential for integrated transportation and sequestration on the proposed Alberta Carbon Grid being developed by Pembina and TC Energy.

The ammonia would be transported via rail to Canada’s WestCoast and shipped to Japan and other Asian markets.

Under the MOA, Pembina and Marubeni will focus on the preliminary Front End Engineering Design (pre-FEED), engagement with various stakeholders, including governments in Canada and Japan, and commercial activities.

The project is expected to be structured as an infrastructure-style, fee-based business with investment grade counter parties. Pre-FEED work is currently expected to be completed by early 2024.

The project could potentially serve as an anchor development to advance Pembina’s ongoing efforts to establish a new growth platform known as the Pembina Low Carbon Complex (PLCC) for energy transition technologies, sustainable fuels, and chemicals like hydrogen, ammonia and methanol.

“With over 2,000 contiguous acres of undeveloped land located in the Alberta Industrial Heartland, Pembina’s vision is to develop an industrial complex for low-carbon energy infrastructure to better enable Pembina and third parties to develop projects, while reducing costs, emissions, and risk,” the release states.

Projects within the PLCC would gain access to land, low-carbon hydrogen, clean power, natural gas and industrial gases, water, CCUS, and the construction and operation of rail assets. Within the PLCC, Pembina would lease land to third parties and provide infrastructure, logistics, and shared services to tenants.

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HY24 hires new managing director

The former head of EDF Pulse Ventures will head up Hy24’s latest investment initiative dedicated to scaling-up clean hydrogen technologies and equipment manufacturers.

Hy24, the hydrogen-focused French and American private equity JV, has hired Guillaume Lesueur as Managing Director, according to a news release.

Guillaume, former head of EDF Pulse Ventures, will head upHy24’s latest investment initiative dedicated to scaling-up clean hydrogen technologies and equipment manufacturers.  

Hy24 is a joint venture established in 2021 by FiveTHydrogen and Ardian. Its first fund – Clean Hydrogen Infrastructure, or “InfraFund” – is targeted at building out the hydrogen infrastructure market. The fund has raised EUR 2bn and has made four investments. More than 50 LPs are involved.

The new investment initiative led by Guillaume will focus on supporting the technology and equipment manufacturing capacities needed to meet the demand for hydrogen across the global supply chain, the release states.

“With over one thousand large-scale hydrogen projects announced worldwide as of the end of January 2023, demand for equipment far exceeds available supply capacity,” the release states. “From upstream to downstream, the manufacturing of hydrogen production, conversion, distribution, retail, storage, and end-use equipment therefore needs rapid acceleration.”

The equipment market is estimated to reach $190bn by 2030.

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US clean fuels producer prepping equity and debt raises

A Texas-based clean fuels producer is close to mandating an advisor for a platform equity raise. It has already tapped Goldman Sachs to help arrange a cap stack in the billions for a project in Oregon.

NXTClean Fuels, a Houston-based developer of clean fuels projects, is preparing a $50m to $100m platform equity raise in the near term and has large debt and equity needs for a pair of projects in Oregon, CEO Chris Efird said in an interview.

The company is close to engaging a new financial advisor for the raise, which will launch late this year or early next, Efird said.

Port Westward

Meanwhile, Goldman Sachs’ post-carbon group is retained for the capital stack on NXTClean’s flagship project at Port Westward, at the Port of Columbia County, Efird said. The $3bn CapEx (including EPC) project is fully permitted by the State of Oregon and is awaiting one federal Clean Water Act permit. An Environmental Impact Statement is expected this fall.

The project is dedicated to producing a split of renewable diesel and SAF, amounting to roughly 50,000 barrels per day total permitted capacity when fully operational.

FID is expected for roughly August 2024, he said. About 30 months from FID the plant will reach COD.

“What we’re most focused on right now is the true senior debt,” Efird said. On the equity side the company is engaged with strategic partners that have indicated interest in post-FID equity.

NXTClean has conversations ongoing with the Department of Energy’s Loan Programs Office, along with commercial project finance lenders.

Red Rock

In April NXTClean acquired what was the Red Rock Biofuel facility in Lakeview, Oregon. That woody biomass-to-SAF facility foreclosed after $425m in investment, following technical and financial issues brought on by the COVID 19 pandemic. NXTClean purchased the facility for $75m in preferred stock at auction on the courthouse steps.

GLC advisors was retained by lead bondholder Foundation Credit to advise on that process, Efird said.

Red Rock is being repurposed to produce carbon-negative RNG for the adjacent Tallgrass Ruby Pipeline, Efird said. The fully-permitted project has a significant amount of equipment already installed or on skids.

A first phase will require a spend of $100m to $150m. Some $50m of equity will augment a balance of debt, raised in part through USDA programming, Efird said. Cash flow from the first phase will help with the second phase, which will bring the capital needs of the facility up to as much as $400m.

Looking forward

Geographically, NXTClean will expand in the Pacific Northwest and British Columbia, Efird said.

Each of NXTClean’s two projects are held by a separate subsidiary. The company has a third subsidiary called GoLo Biomass that focuses on feedstock aggregation, Efird said. It engages with fish processors in Vietnam and used cooking oil suppliers in South Korea to augment supply from large companies.

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US hydrogen developer auditioning bankers

A US-based clean fuels developer has large capital needs for unannounced green hydrogen projects in California and Illinois, as well as an ammonia facility in Texas.

A US-based clean fuels developer has large capital needs for unannounced green hydrogen projects in California and Illinois, as well as an ammonia facility in Texas.

Avina Clean Hydrogen has yet to formally engage an investment banker to raise the equity and debt needed for a trio of projects under development in the US, CEO Vishal Shah said in an interview.

The company, which recently announced the formation of a strategic advisory board composed of executives from companies like Cummins, bp and Rolls Royce, will need $600m or more of debt and between $200m and $300m of equity, as previously reported by ReSource. Capital raising talks are focused on the operating company and project level.

Capital raises for Avina’s 700,000 mtpa green ammonia project in the Texas Gulf Coast and a larger operating company raise will launch next month, Shah said.

“The amounts that we are going to need to raise have gone up,” Shah said. “We are working with a number of banks but we’ve not engaged anyone formally.”

Buildout of the Texas project has been accelerated. The company recently announced an agreement with KBR for that project, which is scheduled to come online next year.

Project level capital has been raised for Texas and a green hydrogen project in Southern California, Shah said. An additional green hydrogen project in Illinois is in development as well.

Finding the renewable power

Renewable power needs for these facilities are big, but Shah said the company doesn’t see a shortage of power. Instead, developers are facing interconnection issues and subsequent cost increases.

Hydrogen developers in California are in many cases offering higher prices for renewable energy than other buyers, Shah said. The issue is that credit-worthy investment counterparties are often seen as more attractive offtakers regardless of the higher price offers from aspiring hydrogen producers.

“I would say California is different,” Shah said. “The offtake market is a challenge.”

There are renewables developers with a genuine interest in hydrogen looking at the sector as a long-term play, Shah said. But for some without a strategic interest in hydrogen, a community choice aggregator offering a 15-year offtake is more certain than a hydrogen developer offering a 10-year offtake; higher price can be seen as a trade-off.

“That’s the nature of the beast, right now.”

Regulatory uncertainty

Investors looking into the space are hesitating to deploy capital in some cases because of uncertainty around IRA clarifications, particularly with regards to the PTC qualifications, Vishal said.

“A lot of the customers, lenders, everybody’s waiting to make decisions,” Vishal said. Offtakers also have hesitations. “Nobody wants to sign long-term contracts in an environment where pricing is not clear.”

Shah said investors should look for offtake when investing in projects. Avina has two of three contracts signed for each of its projects.

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Cutting the electricity out of electrolysis

Milwaukee-based start-up Advanced Ionics is seeking to commercialize an electrolyzer that cuts electricity needs for hydrogen production to as low as 30 kWh per kilogram.

Advanced Ionics is seeking to ramp manufacturing capacity and raise capital as it begins to commercialize an electrolyzer promising to reduce electricity needs, CEO Chad Mason said in an interview.

The Milwaukee-based company is working to demonstrate its low-cost electrolyzer technology through a partnership with the Repsol Foundation.

The technology will be tested locally, but could grow to include additional tests and, eventually, a commercial relationship with the Spain-based energy and petrochemical company.

Advanced Ionics is looking to move into a larger facility in Milwaukee to advance early-stage production of the electrolyzer, which uses steam from process and waste heat to reduce the amount of electricity required in electrolysis.

The company last year raised $4.2m in a seed round led by Clean Energy Ventures, with participation from SWAN Impact Network. It has also received financial support from Repsol and $500,000 from the DOE.

As it scales, Mason said, the company will also need to raise additional capital, but he declined further comment.

Going to market

The Repsol arrangement is part of the company’s early access program allowing potential end users to take a first look at the technology.

“Repsol is just the tip of the iceberg here,” Mason said. “We’re talking to some really amazing partners at some of the largest energy companies in the world. People who use hydrogen today and want to make it green immediately understand what we’re doing.”

Given the concentration of hydrogen use in petrochemicals and ammonia, Advanced Ionics is targeting these sectors for deployment of its electrolyzers to produce clean hydrogen, Mason added.

Mason noted that, as the traditional petrochemical industry dies off over time, it will be replaced by green materials and green fuels like sustainable aviation fuel and biofuels that require hydrogenation to be useable.

“You’ll see a bit of a replacement happening on the petrochemical side, towards a green chemical,” he said, adding that a third potential key market is green steel production using hydrogen.

Thermodynamically favored

The company’s Symbiotic electrolyzers use steam by tapping into excess heat from industrial settings, thereby lowering electricity needs for water splitting to 35 kWh per kg, with 30 kWh per kg possible. That compares to industry averages over 50 kWh per kg.

Advanced Ionics’ water vapor electrolyzer

“We set out to build an electrolyzer specifically that would operate at intermediate temperatures,” he said. “And that allows you to have the synergy with those processes, and the downstream effect is the most cost-effective hydrogen you can get.”

The resulting hydrogen could be available for less than $1 per kg – but, Mason notes, the underlying power price math assumes an abundance of cheap, clean power. The models are usually pricing in two cents per kWh, the availability of which, Mason added, is “extremely geographically dependent.”

“If you’re in Texas, you have a system with wind, solar, and some amount of clean energy grid back-up, it’s pretty attractive,” he said. “Or if you hook up to a hydroelectric facility in the Northwest or in the Quebec area.”

Mason added, “Electrolysis rides on the coattails of cheap, clean electricity. What we have under our control is to make sure we’re using as little electricity as possible.”

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