Sustainable aviation fuel does not lack production routes. HEFA turns waste oils and fats into jet fuel. Alcohol-to-jet upgrades ethanol and other alcohols. Gasification converts woody biomass, municipal solid waste or refuse-derived fuel. Biogas and biomethane can be reformed.

E-SAF combines RFNBO hydrogen with CO2, either via methanol-to-jet or via reverse water-gas shift and Fischer-Tropsch synthesis. Hybrid bio-electrofuel routes combine gasification with RFNBO hydrogen.

Each pathway has real potential. Yet between a promising pathway and a financed plant sits a rigorous test: due diligence. Investors and lenders want to know whether a project is mature, defensible and bankable, not only whether the chemistry works.

Whatever the pathway, the same ten areas come under scrutiny. Here is what each one covers, and the questions every SAF developer should be ready to answer.

Technology, location and operations

1. Feedstock availability and cost

No feedstock, no fuel. The relevant inputs depend on the pathway: waste oils and fats for HEFA, MSW or biomass for gasification, hydrogen and CO2 for e-SAF.

The key questions are whether supply is secured at a viable cost, and how mature the feedstock contracts really are.

2. Offtakers, product and pricing

A plant is only as bankable as the buyers behind it. Due diligence tests whether the product meets market and product requirements, and whether its CO2 intensity and certification will stand up.

It also asks whether offtakers are willing to pay the green premium. As with feedstock, the maturity of offtake contracts matters as much as their headline terms.

3. Power, process and system

SAF plants are complex, integrated systems. Reviewers look at power and water utility requirements, process integration and energy efficiency.

They then ask whether the whole system is cost-competitive, and how long it will take to reach the commercial operation date (COD).

4. Technologies and operation

Maturity is assessed unit operation by unit operation, not only for the process as a whole. Total capex, maintenance and labour costs are scrutinised.

So are emissions to air, land and water. A technology that works at pilot scale may still carry scale-up and integration risk.

5. Location and regulation

Where a project is built shapes almost everything else. Due diligence covers regulatory and permitting status, community support, available subsidies and local environmental factors.

Logistics matter too: how feedstock gets in and how product gets out.

Financials, commercials, execution and legal

6. Financials

The numbers must work for the capital being asked for. Reviewers examine return on capital invested, profit margins and cash flow.

They also check whether costs can be passed through to buyers, and how much capital still needs to be raised.

7. Execution and team

Investors back people as much as plants. They assess skills, expertise and teamwork, timing and track record.

They look at whether the team has the bandwidth to deliver and the objectivity to see its own project clearly. The EPC partners and equipment vendors behind the project are part of the assessment.

8. Geopolitical and security

SAF is a global business, and country risk is real. Due diligence covers taxation and the ability to repatriate cash and capital.

It also weighs local security issues and the security of the trade corridors that feedstock and product depend on.

9. Market

Some of the deepest questions are about conviction. Is there enough belief in SAF, and in aviation itself, to sustain long-term demand?

At the counterparty level, reviewers test the creditworthiness of offtakers and whether the offtaker base is diverse enough.

10. Legal and IP

The first question is deceptively simple: what exactly are we investing in? From there, due diligence examines the legal structure and the rights to use the technology.

It also considers exposure to regulatory shifts that could change the project’s economics.

What the checklist reveals

Read as a whole, the ten areas tell a clear story. A project succeeds or fails as a system, not as a technology.

Contracts sit at both ends. Maturity of contracts appears under both feedstock and offtake. An excellent process between unsecured inputs and uncommitted buyers remains a risky project.

The whole can differ from the sum of the parts. Individual components may be proven, yet process integration and scale-up introduce risks of their own. That is why technology readiness (TRL), commercial readiness (CRL) and manufacturing readiness (MRL) are assessed together with project maturity.

Strength in one area rarely offsets weakness in another. Proven technology in the wrong location, or strong economics behind a stretched team, will still struggle to raise capital.

Both sides of the table need the full picture. Sellers must anticipate where scrutiny will be closest. Buyers must avoid mistakes that come from looking at only part of the picture. Non-technical advisers need enough technical grounding to judge the deal.

For developers, financiers and advisers alike, these are the questions to answer before someone else asks them.

Going deeper: Due Diligence for SAF Projects

Work through this checklist in depth during an in-person masterclass, Bankability and Due Diligence for SAF Projects, on the 24th of May 2027 at the SAF Congress in Amsterdam. It will run as a full day sessions of three blocks, each one and a half hours long, with Q&A built into every session.

Background, concepts and definitions

• Investment mandates and investor profiles. Types of due diligence, what an ideal project looks like, risk tolerance and expected returns. It also covers the pitfalls on both the sell-side and the buy-side.

• SAF pathways and their potential. HEFA, alcohol-to-jet, gasification, biogas reforming, both e-SAF routes and hybrid bio-electrofuels.

Putting theory into practice

• Technical maturity, project maturity and risk mitigation. TRL, CRL and MRL, process and scale-up risk, and technical, operational and product-mix levers.

• Bankability and due diligence. Sell-side and buy-side fundamentals, from feedstocks and certification to defensibility and business model.

• Case study workshop. Delegates can bring their own project, summarise it against the checklist and work through it with the trainer. Prepared examples are available for anyone who prefers not to share a live case.

Tailored content around your interests and needs

The strongest differentiator of this masterclass is not that it is another SAF training course, but that it is structured around the exact due diligence questions that investors, lenders and project developers must answer before a Sustainable Aviation Fuel project can reach financial close.

The programme is built around a ten-area due diligence framework covering feedstocks, technology, operations, commercial structure, financials, execution risk, regulation, legal/IP issues and market fundamentals. It also includes interactive sessions where participants can test their own SAF projects against this framework.

The SAF industry is moving rapidly from ambition to execution. Yet many projects still struggle when subjected to rigorous investor and lender scrutiny.

Who should attend: SAF producers, project developers, project financiers, technology investors, startups and scaleups, technical and M&A consultants, and legal and IP advisers.

Also, if you are working in similar fields such as e-methanol, e-DME, green ammonia of renewable natural gas (e-methane ( e-LNG) this course will be of immense value.

The course includes all session recordings and course materials. It also offers pre-recorded videos with experienced SAF investors from leading international funds, and a certificate of attendance on full completion.

Uniquely valuable is the opportunity for attendees to bring their own projects and test them against the same questions that investors and lenders ask during due diligence.

As SAF projects become larger, more capital intensive and increasingly complex, robust due diligence is no longer a box-ticking exercise. It is becoming a critical factor in determining which projects secure funding and which do not.

For developers, investors, airlines, fuel producers, technology providers and advisers working in SAF, this looks like a highly practical way to strengthen project readiness and investment credibility.

As you your trainer: during the past 9 years I have dedicated my expertise to net-zero projects and technologies through my work at sbh4 consulting, accumulating vast experience in this area from multiple perspectives.

I have supported CINEA in evaluating large-scale SAF, e-methanol, hydrogen and CCS projects for the Innovation Fund in 2023, 2025 and 2026. And, I work with technology providers and project developers to build the best process pathways.

Also, I have led or supported clean fuels feasibility studies and project evaluations for the IFC, EIB and ADB. And I have extensive buy-side and sell-side investment due diligence experience in clean tech with references from top-tier funds and the biggest names in the industry.

Prior, I spent 27 years at BOC Gases, The BOC Group and Linde Gas: 14 of them as a global business leader, and always drawing on my qualification and experience as a Chemical Engineer.

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Unit operations must support system boundary conditions

Consider the case that a liquid solvent-based CO2 capture system, such as a twin-tower amine process, is used upstream of a CO2 liquefier to condition the CO2 for transportation by rail and ship to an offshore geological storage facility.

Imagine that the given boundary conditions are an overall CO2 capture rate of >90% from the emissions source to geological storage and that the liquid CO2 must comply with the Northern Lights CO2 purity specifications.

If the amine-based CO2 capture system were optimized in isolation, it would capture just over 90% of the flue gas CO2. This minimises the size of the absorption tower to reduce capex, and minimises the reboiler energy to reduce opex.

The amine system would typically yield CO2 of around 99% purity with nitrogen as the main impurity. This would then be fed to the CO2 liquefier. In the liquefier, the incondensable nitrogen must be vented from the system. As it is released, it carries with it an amount of CO2 according to the vapour / liquid equilibrium of these two gases. Typically, the vent contains 50% to 60% CO2, in addition to nitrogen which must be purged.

The implication is that the overall capture rate is less than 90% due to the CO2 loss with the purge gas. The end-to-end system no longer meets the given constraints defined in the boundary conditions.

To achieve the >90% capture rate, it will be necessary to increase the CO2 capture rate in the amine absorption towers, increasing both the energy requirement and the equipment size. Optimising the end to end value chain is essential to avoid one process winning, at the expense of another.

Avoiding a zero-sum game

In the case above, it may be decided that the amine system should be replaced with a pressure / vacuum swing adsorption process using a solid zeolite sorbent to capture the CO2. This technique is generally able to produce CO2 of a purity of 95% cost-effectively, with nitrogen being the balance. Whilst the CO2 capture rate might be high, at 98%, the CO2 purity may be low.

However, substituting one technology for another, without consideration of full value chain implications is perilous.

The motivation for substituting the amine-based system for the VPSA unit may be sound, for example to reduce the capex or opex of the CO2 capture aspect of the process. However, the knock on effect is negative consequence to the operation of the CO2 liquefier.

The electrical energy input required to liquefy CO2 of 99% purity from the amine system is lower than that required to liquefy CO2 of 95% purity from the VPSA. This is because the compressors must do un-productive work to handle additional inert nitrogen gas. Also, the compressor discharge pressure is increased due to the presence of a higher amount of incondensable nitrogen. This also increases the energy requirement.

The net result could to be that the savings achieved by implementing the VPSA system are negated by the increased capex and opex in the liquefier compressor.

A holistic approach to optimisation

To optimize the CO2 capture technology, it makes sense to consider the requirement at the end of the CCTU/S value chain. What is the required purity of CO2? What is the required temperature and pressure condition?

If the goal is to compress supercritical CO2 into a geological storage site, and CO2 transmission is by pipeline, the CO2 capture technology can be selected to produce CO2 gas (rather than liquid) which can be compressed.

On the other hand, if the end-game is utilisation of the CO2 in an e-methanol or Fischer Tropsch e-fuels production process, and liquid CO2 will be transported by rail, there is a requirement to produce liquid CO2 at the capture location, or at a CO2 transfer terminal, where liquid CO2 can be loaded onto the train.

Cryogenic CO2 capture to the fore

If CO2 is required as a gas for transmission in a pipeline, expending additional energy required to liquefy CO2 is wasteful. On the other hand, if liquid CO2 is the requirement, the energy for liquefaction must be consumed at some point in the value chain. In this case, it makes sense to integrate CO2 capture with CO2 liquefaction. This is the essence of cryogenic CO2 capture.

The physical property of CO2 that makes cryogenic CO2 capture technically feasible is that CO2 liquefies at a much higher temperature than nitrogen and oxygen which are major components in post-combustion flue gases.

Cryogenic CO2 capture processes cool the entire flue gas stream to the point where the CO2 forms a liquid or solid, but the other components remain as gases. Several critical aspects influence the operability and energy efficiency of this process.

1) Moisture must be removed from the flue gas using a drying process, prior to cooling the flue gas below 0 °C. This is prevent water forming ice, which would block the process.

2) Nitrogen and oxygen in the flue gas are cooled along with the CO2. This serves no benefit at the outlet of the process, so the cold energy must be recovered from these gases. This is achieved using a heat exchanger to cool the incoming flue gas against the cold oxygen and nitrogen exiting the process.

3) CO2 forms a solid directly from the gas under certain temperature and pressure conditions. If solid CO2 accumulates, it will block the process. The transition of CO2 from gas to liquid must be carefully managed through appropriate process control and respect of CO2’s unique phase diagram.

Several pioneers have overcome the issues associated with cryogenic CO2 capture.

CarbonCloud from Revcoo

Founded in 2021 by Hugo Lucas and based in Lyon, France, Revcoo’s CarbonCloud is exactly that. Cryogenic liquid nitrogen is sprayed into the pre-cooled flue gas. As the CO2 in the flue gas is cooled by the liquid nitrogen, it solidifies. The solid CO2 particles are separated from other gases in a cyclone. The solid CO2 is then warmed to yield liquid CO2.

To create the liquid nitrogen, mechanical energy is required for the liquefier compressor. This is generally provided from electrically powered motors. To maximize the energy efficiency of the process and minimize the amount of electricity required for the nitrogen liquefier, the cold flue gas leaving the cyclone pre-cools the warm incoming flue gas before it enters the CarbonCloud chamber.

Additionally, cold energy is released from the solid CO2 as it converts to liquid. This cold energy provide additional cooling for the flue gas entering the CarbonCloud.

A CarbonCloud pilot plant capable of removing 2 tonnes per day of CO2 was installed at the Eiffage lime kiln in France in 2024. Lime making releases unavoidable geogenic CO2 as limestone is converted to lime. Similar to cement, the geogenic CO2 emissions from lime making can only be decarbonized with the use of CO2 capture.

SES and CCC

Sustainable Energy Solutions (SES), founded in 2008 by Dr. Larry Baxter and based in Orem, Utah. In 2020, Chart Industries acquired SES as part of their drive to focus their business towards the energy transition. Chart has since become an acquisition target for Baker Hughes.

Chart’s Cryogenic Carbon Capture process (CCC) exploits the gas to solid deposition phase change that is unique to CO2. The entire flue gas stream is cooled to around -120 °C which causes deposition of CO2 as solid particles. After the solid CO2 particles are formed, they are converted into liquid CO2 through carefully controlled temperature and pressure changes.

During cooling of the flue gas, condensible pollutants such as oxides of sulphur (SO2) and nitrogen (NOx) are liquefied before CO2 deposits as a solid. These liquids can be separated from the flue gas. Any traces of these pollutants that flow through into the liquid CO2 are solidified and can be removed by filters.

The simultaneous removal of pollutants is a feature of CCC aligns it well with greenfield projects, because it eliminates the need for additional SO2 and NOx removal equipment.

A 1 tonne per day containerised CCC pilot plant has been used to process cement making and power plant flue gases. A 30 tonne per day demonstration plant at Central Plains Cement Company in Sugar Creek, Missouri has also been commissioned.

Building on natural gas processing

Cryogenic technologies for CO2 removal from natural gas have been implemented for many years. The Ortloff CO2 Fractionation / Dual Refrigerant Fractionation (DRCF) process (owned and licensed by Honeywell UOP) is ideal to liquefy and capture very high concentrations of CO2 (between 30 and 80%).

It yields very pure CO2 and operates in a manner which prevents solid CO2 formation. On the other hand, due to the vapour liquid equilibrium of the CO2 and the incondensable gases, around 15 to 20% CO2 remains in the flue gas. Where partial CO2 capture is appropriate, this is acceptable. To achieve capture rate of >90%, a polishing technology such as an amine solvent system must be used after the DRCF process.

Chart’s CCC is fundamentally similar to the CryoCell process, developed in Australia by Cool Energy Ltd to remove CO2 from natural gas. ExxonMobil’s Controlled Freeze Zone (CFZ) is another gas processing technology that relies on formation of solid CO2 followed by desublimation of CO2 to the liquid phase. The main difference is that CCC and CarbonCloud are optimised to remove CO2 from flue gases, not from a methane-rich natural gas stream.

With the benefit of hindsight, some might say this supply chain disruption was inevitable. The 12-day war in June 2025 clearly indicated the extent to which volatility was mounting in the region. Closure of Hormuz has been threatened in the past. And, due to security concerns, Suez Canal cargoes in 2025 were reduced by around 60% compared to 2023.

The nature and location of the next international flashpoint is not known, what is clear is that international energy flows are subject to changes triggered by geopolitical events. The world is entering a ‘predictably chaotic’ state.

A responsible transition from global to local supply

Since the end of the cold war, the world has benefitted from globalisation and the ‘peace dividend’. International trade of fuels has kept inflation under control by allowing energy commodities to be sourced from the lowest-cost worldwide location.

But the present and the future are clearly different. We are living in a new era. One where resilience, localised supply chains and energy security will be valued at a premium. But these objectives must still be achieved affordably, and with respect to the avoidance of long-term catastrophic events, such as climate change.

The time for local, resilient, climate-friendly energy security has come.

Home-grown biomethane

Local energy sourcing is a fundamental driver of supply chain resilience and bio-based energy is generally produced and consumed locally. A driver for this is that the volumetric and gravimetric energy density of the biomass feedstocks such as wood, grass, bagasse and maize is low, compared to liquid fuels such as gasoline or diesel.

Biogas, upgraded to biomethane, is one of the main bio-energy sources utilised today. Almost all biomethane is produced in anaerobic sludge digesters of various kinds. The feedstock is often a purpose -grown crop such as grass or maize. To balance continuous demand for energy with growing seasons, these feedstocks can be stored as silage in horizontal silos for time shifting from summer to winter months.

Farm waste from poultry, pig and dairy farms, sewage sludge and food waste from urban centres are generally available through the year and are also excellent feedstocks for biogas production.

Despite many efforts to adapt the anaerobic sludge digestion, this process has not yet been successfully deployed at scale for highly cellulosic feedstocks such as straw and waste wood. Technological breakthroughs in this field will unlock many stranded bio-energy sources.

Conversion of woody biomass to energy gases

Research into the conversion of residual forestry waste and other cellulosic post-harvest wastes has been ongoing for decades. Current technologies centre around various thermal techniques such as torrefaction, pyrolysis and gasification.

Often, the product from these technologies is syngas, which contains a high amount of hydrogen and carbon monoxide. A notable exception is Thermally accelerated Anaerobic Digestion (TAD), which has been developed by Biezel Green Energy in India to convert green crop residues to biomethane and hydrogen.

To unlock the woody biomass to biogas pathway, G4 Insights, in Canada, has developed and proved a proprietary process which converts cellulosic biomass to biomethane. Their technology pathway is referred to as PyroCatalytic Hydrogenation (PCH).

Process flexibility and profitability

A unique feature of the PCH process is that it produces biomethane, biosyngas and hydrogen at various stages in the process. Biochar and biogenic CO2 are also important co-products. According to the desired product mix, PCH can be designed to optimise production of any one, two or three of these energy gases in a ratio that is required by the system user.

Production of more than one bio-energy gas enables revenue diversification from the investment to reduce the commercial risk. During operation, some deviation from the design point can also swing the product mix towards market needs. This enables arbitrage to maximise production of the most profitable product(s) at any moment in time.

The biogenic CO2 can either be sequestered, or liquefied and sold into the merchant CO2 market for applications such as pH regulation in water, beverage carbonation and food freezing. The biochar can be monetised as a soil improver, and will also be eligible for carbon dioxide removal certificates since it permanently binds atmospheric carbon which the tree initially absorbed from the atmosphere into solid biochar.

Electrified reforming

In the PCH process, both the pyrolysis and the SMR stages require heat input to drive the chemical reactions.

The SMR requires heat input, and it also emits heat because the reformate gases are cooled between the WGS stage and the PSA unit. This heat can be recovered and used to drive the pyrolysis reaction. This process integration maximises the energy efficiency of PCH.

Classical SMRs use a flame box to heat up multiple tubes filled with reforming catalyst, through which the methane and steam flow. The flame is generally fired with additional methane combined with tail gases from the downstream PSA unit.

In the case of PCH, bio-methane produced in the catalytic hydrogenation reactor, or natural gas, can be used. On the other hand, the SMR can be electrically heated. Electrical heating of the SMR with renewable power, such as that from hydro, wind and solar resources, simultaneously reduces the carbon intensity of the bio-methane and maximises the bio-methane yield.

Electrified reforming and electrically heated SMRs are being developed by Topsøe with their eREACT™ system and Sypox. In a classical flame-heated SMR approximately one third of the methane feed is to the burner. Therefore, if this energy input is replaced by renewable electricity the CO2 intensity of the products from the SMR can be reduced by 30%.

Carbon-negative energy gases

When the overall carbon balance of the PCH process is considered, the bio-methane is produced with a negative carbon intensity. Meaning, that its production has resulted in the removal of carbon dioxide from the carbon cycle.

According to the economic requirements of a project, the revenues from one product can be used to partially offset the costs of producing another product. Thus, biomethane can be sold at a price which is less than the cost of natural gas as a fossil fuel.

There are very few renewable energy processes that can achieve fossil fuel cost parity: PCH is one of them. Beyond that, there are very few carbon-negative pathways to produce transportable energy vectors such as bio-hydrogen, bio-syngas or biomethane. PCH is able to achieve all three.

Secret sauce

Research into the catalytic conversion of un-cleaned pygas has taken place over many years. Until now, this direct conversion of un-cleaned pygas has been held back by the propensity of tars in the pygas to coke onto the catalyst, which generally uses a nickel-based compound as the active material.

In the PCH process, conversion of pygas to biomethane is achieved in the catalytic hydrogenation reactor. There are two critical differences that this concept introduces which overcome problems from past attempts to directly process pygas. Firstly, hydrogen is introduced into the reactor. Secondly, the reactor design itself is proprietary to G4 Insights.

The secret sauce built into the G4 Insights technology is the internal design of the hydrogenation reactor. It carefully controls the strong exotherm to avoid catalyst damage. Simultaneously, it achieves an exceptionally high conversion of tars and other chemicals in the pygas to methane through tight control of the temperature profile in this reactor.

2,000 hours of testing in Canada have proven the validity of the PCH process and the robustness of the hydrogenation reactor. G4 Insights has gained sufficient operational data to model the catalyst performance.

As with almost all catalytic processes, catalyst replacement at periodic intervals is required. In the case of PCH, the catalyst loading and replacement is a very small incremental cost, because the main active ingredient is nickel, not a precious metal such as platinum, palladium or ruthenium.

Given the number of components in an electrolyser system, and the multiple options for each component, there are thousands of degrees of freedom that an electrolyser OEM can leverage to optimise their product for cost, efficiency, dynamic response, or durability.

Only the best electrolyser OEMs, using the best components, are able to out-perform their rivals on multiple performance attributes. Component-level choices matter. And on top of that, there must be a cohesive concept which integrates the holistic design, from feed water entering the system to pure, pressurised hydrogen leaving it.

Technology classes

There are four broad categories of electrolyser technology to split water into hydrogen and oxygen

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1. Alkaline water electrolysers (AWE) operate using an electrolyte which contains about 30% by mass of potassium hydroxide (KOH). This is referred to as lye and is an extremely alkaline medium.

2. Anion exchange membrane (AEM) electrolysers also use an alkaline electrolyte. In comparison, to the AWE technology, the AEM electrolyte will either have a lower concentration of KOH or use a benign bicarbonate solution.

3. Proton exchange membrane (PEM) electrolysers use pure water at the electrolyte. During electrolysis, an acidic environment is created. This is a key differentiator between PEM electrolysers and the AWE and AEM classifications.

4. Solid oxide electrolyser cells (SOECs) use a solid electrolyte. Their design and operation is vastly different to AWE, AEM and PEM systems, which rely on liquid electrolytes. Furthermore, SOECs generally operate in the temperature range 700 to 900 °C – significantly higher than AWE, AEM and PEM technologies which operate in the range of 60 to 120 °C.

Acidity is unavoidable in PEM systems

Materials selection for AWE and AEM electrolysers operating in an alkaline liquid is different to the case for PEM. Additionally, the AWE and AEM stacks are more robust than PEM stacks meaning they are more tolerant of some impurities in the electrolyte.

The PEM membrane must be manufactured from an extremely resilient polymer to avoid it being damaged by the acidity surrounding it. A fluorinated, sulphonated polymer called perfluorosulfonic acid (PFSA) is the default choice to achieve this goal.

Using a fluorinated polymer is a double-edged sword. On the one side, the fluorine makes the polymer robust. On the other side, the acidity in the PEM stack is so extreme that some fluorine is released from the PFSA membrane as hydrofluoric acid (HF). HF is one of the most aggressive acids known to chemistry.

Over time, HF attacks the highly sensitive PEM electrolyser’s proton exchange membrane, which is intentionally very thin to reduce ohmic losses

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Durable PEM membranes

In essence, a PEM stack with a PFSA membrane is designed to destroy itself. The challenge is to balance the design to achieve several years of stable operation at high efficiency before the stack deteriorates to such an extent that the electricity input required to generate hydrogen rises to such an amount that re-investment in new stacks is cost-effective.

Avoidance of HF would be possible if an alternative membrane were to be used. Selection of a membrane that avoids fluoropolymers would also reduce concerns related to ‘PFAS’: per- and polyfluoroalkyl substances which are known as ‘forever-chemicals’ which are harmful to the environment and extremely difficult to break down in nature.

Toray, and several other companies are working to develop fluorine-free, PFAS-free PEM membranes. However, at present, the state of the art relies on PFSA, due to its resilience.

Feed water purification

The feed water to the electrolyser must be purified to an extremely low level of ionic conductivity. The purification equipment for this can include ultrafiltration, reverse osmosis, electro-deionisation and ion exchange resin beds.

However, even the most robust purifiers allow a few parts per billion of contaminant ions such as calcium, magnesium and iron being introduced to the electrolyser. The presence of iron oxide particles in the size range of 0.1-5 µm in the electrolyser recirculation water can be observed through ‘rouging’. Rouging is caused when pure water at around 60 °C comes in contact with stainless steel.

Some of these metallic ion impurities are very damaging to the membrane. Big cations such as calcium and magnesium are membrane killers because they block the proton transfer ‘pores’ in membrane.

Blockages in the proton exchange membrane lead to a progressive increase in ohmic resistance. In turn, that means a reduction in the stack efficiency and an increase in electricity consumption per kg of hydrogen produced. This is a core reason for PEM stack degradation.

Limitations of stainless steel

Selection of stainless steel for water purification system and PEM electrolyser pipework is common because it is strong and releases fewer ions into the water than carbon steel. However, even the highest grades of stainless steel can release metallic ions into the feed water and circulating water.

Specification of drawn stainless steel tubing with internally polished surfaces is essential if this material is used in PEM electrolysers and ultra-pure water treatment systems. This is potentially a limitation to the scale up of PEM electrolyser stacks because this type of pipework is only available at smaller diameters.

The use of large-diameter stainless steel pipe, fabricated with a welded seam would be fatal for a PEM electrolyser. At a microscopic level, the weld is rough and porous and may be a catastrophic source of ionic contamination. Similarly, when joining stainless steel piping sections, welds must be avoided.

The case for plastic pipework

An alternative approach to minimise the potential for damage to the membrane is to minimise the use of metallic pipework in contact with the feed water and ultra-pure water in the electrolyser recirculation circuit. With fewer impurities reaching the membrane and catalysts, the stack degradation rate is reduced and its usable lifetime is extended.

Similar to the many grades of steel and stainless steel that might be selected, there are many types of plastic that are used to construct pipes. Not all of these are suitable for use in PEM electrolysers. Only appropriate, sophisticated engineering plastics should be used.

Engineering plastics

There are many different plastics that we encounter in our daily lives. Polyethylene (PE) is commonly used to make bags and food packaging. Polypropylene (PP) is denser and is preferred for car parts and sturdy children’s toys such as a garden slide. Applications of Polyvinylchloride (PVC) range from construction materials for window frames to medical devices.

Engineering plastics differ from household plastics due to their enhanced properties of temperature, pressure or chemical resistance. When designing a PEM electrolyser, superior performance in all three of these attributes is essential.

PP and PE are used in ambient temperature applications such as water purification systems and cooling water circuits in electrolysers.

For PEM water circulation, where the temperature is around 60 °C, we select premium grades, such as PP-H. PP-H is constructed from a homopolymer material, and the manufacturing process ensures very smooth internal wall surfaces and ensures virtually no extractable ionic or particulate contamination is present.

Moving beyond the water treatment system, PVDF and ECTFE are highly stable fluoropolymer materials which are suitable for use in the condensate water return line from the oxygen phase separator. They are non-corrosive and therefore minimise iron ion release and avoid rouging of the recirculation water and damage to the stack.

PVDF is supplied to highly sensitive applications in the pharmaceutical, biotechnology and semiconductor sectors for many years. It is specially cleaned to be oil- and grease-free. At present, we are experiencing a high degree of interest from electrolyser OEMs to use these materials in PEM systems at pressures of up to around 10 bar.

PVDF-HP fittings are generally manufactured in a ISO Class 5 cleanroom: the same category that is used to manufacture less-critical semiconductor components.

Pressure limitations

Many PEM electrolysers produce hydrogen at an elevated pressure between 20 and 40 bar. A notable exception to this is Siemens Energy’s Elyzer-P which operates close to atmospheric pressure. The oxygen side of PEM systems can either be at a low pressure in the order of 3 bar, or at an elevated pressure similar to the hydrogen side of the system.

There is a trade-off between temperature and pressure when using thermoplastic plastic components: at higher temperatures, the maximum safe working pressure is reduced. PEM electrolysers generally operate at around 60 °C and the maximum pressure rating of PP is reduced by half at this temperature compared to the allowable pressure for operation at 20 °C.

Similar to PVDF, Ethylene Chlorotrifluoroethylene (ECTFE) is a thermoplastic with excellent chemical resistance. ECTFE has some advantages over PVDF, namely it is less susceptible to chemical stress and can be used at higher temperatures. These characteristics make it ideal for electrolyser piping circuits in PEM electrolyser systems.

Gases, liquids and oxygen compatibility

In PEM electrolysers plastics are generally used to transport liquids, not gases. A primary application is in the feed water purification and conditioning area where the water is purified to remove particles, dissolved organic compounds, gases and ions.

In addition to selection of appropriate engineering plastics, these components must be cleaned to remove any traces of oils or grease that may have been used during manufacturing. For valves, this is especially important since it would not be appropriate for lubricants that might be used on the moving parts of the valve stem to enter the electrolyser feed water.

The phase separators which allow the oxygen and hydrogen gases to be removed from the recirculating water are generally manufactured from stainless steel. They may need to be certified pressure vessels, and the use of plastics in this instance may not be appropriate.

Downstream of the phase separator, some PEM and AEM electrolysers are being built with plastic pipes and fittings in the condensate water return lines from the phase separator to the stack.

Downstream of the phase separators stainless steel is generally specified for pipework and valves in contact with the oxygen and hydrogen gases.

Stainless steel can easily be cleaned to be compatible with oxygen gas. Furthermore, it is non-flammable and can be constructed to tolerate very high pressures.

The main cost driver for green and blue fertilizers is the increased production cost of clean hydrogen. However, as the amount of hydrogen in the fertilizer decreases, the impact of the higher cost for green or blue hydrogen diminishes. The reason is that the downstream stages to produce ammonia and ammonia derivatives remain un-altered, whatever colour hydrogen they are fed with.

Ammonia derivatives dilute the clean premium

Added-value ammonia derivatives such as urea, ammonium sulphate (AS), diammonium phosphate (DAP), ammonium nitrate (AN) and calcium ammonium nitrate (CAN) dilute the green or blue hydrogen cost to reduce the ‘clean premium’ to a more affordable level.

Hydrogen is 17.8% of the mass of ammonia, with nitrogen being the remainder. The hydrogen content in AN is reduced to 5%. And as the AN is converted to CAN, hydrogen falls to only 3.5% of the total mass.

As the mass of hydrogen in ammonia derivatives decreases, so does its cost within the product. In the case of DAP and CAN, hydrogen represents around 41% of the product value, whereas in ammonia it is 73%.

Additionally, DAP and CAN are inert solid fertilizer granules which can be transported more easily than liquid ammonia, which is both toxic and flammable. For safety reasons, the use of AN as a fertilizer is prohibited, driving a high-value regulated European market for CAN.

Adding value to clean ammonia through ammonia derivatives significantly improves the business case for clean fertilizer value chains.

Air gases for ammonia derivatives

The Villeta Green Fertilizer Project is the flagship development of ATOME PLC. Villeta is an integrated complex, where green hydrogen will be produced using 110MW of electrolyser capacity fed with renewable electricity from the Itaipu dam.

Additionally, cryogenic air separation will produce gaseous nitrogen from the source of renewable electricity. This will be reacted with the green hydrogen in an ammonia synthesis plant. Conversion of the ammonia to nitric acid and the ammonia derivatives AN and CAN will also take place at the 30-hectare site.

In some nitric acid plants, oxygen facilitates process intensification in the absorber, where gaseous oxides of nitrogen are dissolved in dilute nitric acid to enrich the acid to the required commercial concentration.

In integrated sites where an air separation unit is included in the scheme to generate nitrogen for the ammonia production, or an electrolyser is present to generate hydrogen for ammonia synthesis, oxygen can beneficially be recovered as a co-product from these unit operations.

CAN and DAP production

Located in Puerto Sara, approximately 50 km south of Asunción, Villeta sits close to the east bank of the Paraguay River close to the Paraguay-Paraná waterway. This connects the site to several MERCOSUR countries through a regional river transport system.

Villeta is designed to produce CAN and will require circa 170 tonnes per day of dolomite. This rock will be sourced from local mines, integrating the facility into the Paraguayan economy.

Following Villeta, ATOME is planning a further ammonia derivatives development in Paraguay. The 300 MW Yguazu project will diversify their product scope to DAP.

ATOME’s Paraguayan projects are designed to reduce fertilizer imports to the MERCOSUR region and replace grey ammonia production from fossil fuel reforming with green ammonia production from 100% renewable electricity.

By producing green fertilizer at cost parity with the landed cost of gas-based grey hydrogen in South America, ATOME’s projects in Paraguay serve climate goals and address the needs of the region’s agricultural sector. And, by producing exportable added-value fertilizers such as CAN, the project will produce an internationally competitive ammonia derivative.

Bankability above all

The economic viability of green hydrogen production is dependent on the availability and cost of renewable electricity, which constitutes 60-70% of the production cost. Unlike many green hydrogen projects that rely on non-programmable wind or solar power, Villeta will utilise the 14 GW Itaipu dam as a firm supply of green electricity.

The Villeta project will utilise Casale’s Flexigreen® technology, which is optimized for renewable electricity-fed ammonia plants. While the hydropower source is remarkably firm, the Flexigreen® design allows the process to turn down to 10% of nominal capacity. This allows the dam to supply other customers during periods of peak demand and ensures that the Villeta plant will be able to adapt to any potential future connection to integrated wind and solar renewable energy sources.

To de-risk the construction phase, in April 2025, ATOME and Casale signed a fixed-price, lump-sum EPC contract valued at $465 million. The contract guarantees that production will commence within 38 months of the construction start date. The use of proven technologies and the experience that Casale has in the CAN value chain maximises the bankability for equity investors and creditors.

A significant commercial milestone for Villeta was closure of a 10-year offtake agreement with Yara International. The agreement, finalised in September 2025, commits Yara to purchase the entire 260,000 tonne-per-year CAN production. This “take-or-pay” structure will fully cover the costs of energy, operation and capital depreciation. It therefore serves as the foundation for the project’s bankability.

Green hydrogen and CCS to combat CBAM tariffs

A benefit of producing green fertilizers is that they have a very low CO2 intensity and are therefore not subject to the carbon border adjustment mechanism (CBAM) when they are imported to Europe. Blue ammonia and ammonia derivatives will have a similarly competitive position.

Due to the CBAM, some of the additional costs incurred when producing reduced CO2 intensity products are neutralised once the product is landed in the EU and all taxes and tariffs have been paid. This supports the international competitiveness of decarbonised products and can help to build a business case for added-value clean ammonia and ammonia derivatives production.

When ammonia is made from steam methane reforming of natural gas, CO2 leaving the reformer must be removed prior to the catalytic Haber Bosch ammonia synthesis reaction.

The active ammonia synthesis catalyst is iron. All molecules containing oxygen, such as water, carbon monoxide and CO2 must be removed from the syngas before it is fed to the ammonia synthesis loop. Otherwise, the iron catalyst is oxidised and becomes ineffective. Therefore, every natural gas-fed ammonia facility integrates a CO2 capture plant.

In some facilities, about 60% of the captured CO2 is combined with ammonia to make urea. However, the residual 40% of the CO2 from the SMR (and all of the CO2 from ammonia plants that do produce urea) can be permanently sequestered.

Permanent CO2 storage reduces the CO2 intensity of their downstream nitrogen fertilizer products, but add only a marginal incremental cost for CO2 conditioning, transportation and geological storage.

Petrobras has operated geological CO2 injection schemes linked to enhanced oil recovery for many years in the Santos Basin. They have sequestered more tonnes of CO2 offshore than any other operator worldwide.

So, in addition to green ammonia being produced in South America, the continent has the potential to produce blue molecules also.

DAP and AS integration for value-added ammonia derivatives

CO2 capture from DAP production will be implemented from 2027 at OCP’s Jorf Lasfar industrial platform in Morocco. The initiative is part of OCP Group’s decarbonization roadmap, which aims to achieve carbon neutrality across scope 1, 2 and 3 emissions by 2040. It also addresses international competitiveness by reducing the CO2 intensity of DAP.

The captured CO2 will be used by OCP Green Water for pH adjustment and re-mineralisation of drinking water in support of a local reverse osmosis desalination plant. This aligns to Morocco’s goal of meeting all of the nation’s water needs through unconventional water sources by 2027.

As an additional use case for the captured CO2, INNOVX will build a facility that combines captured CO2 and waste phosphogypsum to produce AS.

The Merseburg Process is the most common pathway to achieve this: it reacts aqueous ammonia with CO2 to produce ammonium carbonate. Phosphogypsum is then reacted with ammonium carbonate to yield calcium carbonate and the target product ammonium sulphate.

Calcium carbonate is a recognised permanent sink for CO2, so this pathway sequesters CO2 emissions from the DAP process through mineralisation and enables integrated production of DAP and AS.

AS – ideal for sub-tropical climates

AS was the first commercially available nitrogen fertilizer but it was displaced in many markets by ammonia and urea because they have a higher nitrogen content by mass.

However, AS is still used extensively in Brazil where it is suitable for the local soil, which contains very low levels of sulphur. Sulphur is essential to grow protein-rich crops such as soya beans, which are used locally for beef production and are exported.

Additionally, AS has a lower ammonia volatilisation rate than urea. This is important in the warm Brazilian climate and is a factor that leads to its use in South East Asia for growing wheat and rice.

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