Interview: hydrogen & e-fuels — a buyer’s guide for aviation investors

Sustainable aviation fuel (SAF) is an essential pillar of the aviation sector’s decarbonisation plans, but most current supplies are derived from bio‑based pathways that rely on waste oils, fats and crops. These feedstocks are limited: global used cooking oil (UCO) and tallow availability is estimated at roughly 3.7 billion gallons per year and could rise to only 5–10 billion gallons by 2030—barely enough to meet 1–2 % of long‑term aviation fuel demand. Producing bio‑SAF from vegetable oils would require dedicating around 5 % of the European Union’s arable land to energy crops, a trade‑off that few governments are willing to make. Investors therefore increasingly turn their attention to e-fuels, synthetic hydrocarbons generated by combining green hydrogen, captured carbon dioxide and renewable electricity. These so‑called power‑to‑liquid (PtL) fuels promise a scalable alternative to bio‑based SAF, but they remain expensive and depend on complex supply chains.

This buyer’s guide distils insights from practitioners across the hydrogen and e-fuel value chains to help investors evaluate projects, understand feedstock constraints and identify where capital will have the greatest impact. It combines examples from North America’s emerging e-fuel sector with lessons from Europe’s more mature policy environment.

Why feedstock matters

Bio‑based SAF has a hard ceiling. Waste oils and animal fats are an attractive feedstock because they deliver a 40–80 % lifecycle emissions reduction compared with fossil jet fuel. However, global UCO supplies were estimated at 3.7 billion gallons in 2022 and are expected to reach only 5–10 billion gallons by 2030. Even with improved collection networks, this resource could satisfy just a fraction of future demand. Feedstock prices are also volatile—UCO prices tripled in some markets due to competition from renewable diesel—and waste oils are concentrated in specific regions. Vegetable‑oil‑derived SAF competes with food production and raises land‑use concerns.

Ethanol‑to‑jet: abundant feedstock, but sustainability questions. The United States produces roughly 30 billion gallons of ethanol per year; this plentiful, low‑cost chemical can be converted into SAF via the alcohol‑to‑jet (AtJ) pathway. LanzaJet’s Freedom Pines facility in Soperton, Georgia, opened in January 2024 and can produce around nine million gallons of SAF and one million gallons of renewable diesel annually, making it the world’s first commercial ethanol‑to‑jet plant. Ethanol is a scalable feedstock, but corn‑based ethanol has indirect land‑use change emissions, high water demand and relatively low carbon efficiency (about 60–90 % for the kerosene fraction). Investors must examine the sustainability credentials of the ethanol supply and ensure producers comply with emerging carbon accounting rules.

E‑kerosene and e‑methanol: energy‑constrained pathways. E‑fuel production requires only water, renewable electricity and captured CO₂, offering unlimited feedstock scalability. But these ingredients come with their own constraints: producing 1 kg of green hydrogen needs 50–56 kWh of electricity and roughly 20–30 L of water, and each kilogram of e‑kerosene requires 0.8 kg of hydrogen and 3.1 kg of CO₂. Direct air capture of CO₂ currently costs $400–1,000 per tonne, though costs are expected to fall as deployment scales. The entire PtL conversion chain operates at only 20–30 % efficiency, meaning that 3–5 units of renewable electricity are needed to produce 1 unit of fuel energy. These factors drive costs: today’s e‑kerosene can cost €5 per litre—4–10 times more than conventional jet fuel.

Practitioners’ insights: what’s working

Leveraging existing CO₂ streams reduces costs. A recent analysis from the Environmental Defence Fund highlights how pairing waste CO₂ from ethanol plants with surplus renewable electricity could slash e-fuel costs by half. The U.S. ethanol industry produces between 42 and 49 million tonnes of CO₂ annually, yet only about 5 % is sold for industrial uses. Capturing this biogenic CO₂ and converting it into synthetic fuel could provide an abundant, low‑carbon feedstock while enabling ethanol producers to earn tax credits under the 45Q carbon sequestration incentive. The EDF paper projects that a dynamic, supply‑driven e-fuel industry could meet most or all of U.S. jet fuel demand by 2050 and a significant fraction by 2030. Investors should seek projects that secure access to existing CO₂ streams—whether from ethanol plants, ammonia facilities or natural gas processing—and integrate with local renewable energy systems to minimise electricity costs.

North American projects are scaling rapidly. Several e-fuel demonstrations illustrate how project developers are approaching feedstock and renewable power:

• Freedom Pines (Georgia). LanzaJet’s alcohol‑to‑jet facility in Georgia produces nine million gallons of SAF per year using ethanol feedstock. It is supported by the U.S. Department of Energy’s SAF Grand Challenge, which aims to supply 3 billion gallons of domestic SAF by 2030. The project demonstrates that AtJ technology is commercially viable, but its scale remains tiny relative to total U.S. jet fuel demand (~18 billion gallons per year). Offtakers include airlines and logistics companies seeking to meet voluntary SAF commitments. The facility underscores the importance of reliable ethanol supply and robust offtake agreements.

• ETFuels projects (Texas). Irish developer ETFuels is planning a portfolio of e‑methanol plants in Texas. Its flagship Rattlesnake Gap project will use about 500 MW of wind and solar and battery storage to produce 120,000 tonnes of e‑methanol per year. Sister projects in the Texas Panhandle target 115,000–120,000 tonnes per year of e‑methanol and collectively represent more than 2.5 GW of renewable capacity. E‑methanol can be converted into e‑kerosene via the methanol‑to‑jet process; each project is expected to avoid 230,000–240,000 tonnes of CO₂ annually. Investors should note that these plants are still in the front‑end engineering stage and require billions of dollars in capital.

• HIF Matagorda (Texas). HIF Global’s Matagorda e-fuels facility plans to produce 1.4 million tonnes of e‑methanol per year, recycle 2 million tonnes of CO₂ and deploy 1.8 GW of electrolyser capacity, supported by about US$7 billion in investment. It aims to create 4,000 construction jobs and 140 permanent jobs. The project highlights the scale required for e-fuel facilities to make a meaningful dent in aviation emissions and the need for long‑term CO₂ supply agreements.

These examples illustrate that North America is beginning to catch up with Europe’s e‑SAF pipeline. They also reveal the importance of aligning renewable generation, electrolyser capacity, CO₂ supply and offtake contracts—any weak link can derail project economics.

What isn’t working

Feedstock and power constraints still bite. While e-fuels avoid the land‑use and waste‑oil limitations of bio‑SAF, they are constrained by renewable electricity, water and CO₂ supply. Each kilogram of e‑kerosene requires 0.8 kg of hydrogen, 3.1 kg of CO₂ and roughly 50–56 kWh of electricity. The low efficiency of PtL pathways means that scaling production to meet even a fraction of aviation demand would require tens of thousands of terawatt‑hours of new renewable generation. Massive electrolyser deployment will strain supply chains and could tighten the market for critical minerals. CO₂ capture is also a bottleneck: direct air capture remains expensive and energy intensive, and industrial sources such as ethanol plants can supply only about 48.7 million tonnes per year.

Projects remain pre‑FID and capital intensive. Europe counts approximately 56 e‑kerosene projects, but as of mid‑2025 none has reached final investment decision and most are still feasibility studies . Capital costs for e‑kerosene plants currently range from $500–1,200 per tonne of annual capacity, so a 100,000 tonne per year facility requires roughly $50–120 million of investment. Large plants like HIF Matagorda involve multi‑billion‑dollar budgets. Investors should be prepared for long development timelines, regulatory uncertainty and financing structures that may include government grants, tax credits and long‑term offtake contracts.

Carbon accounting rules are tightening. To qualify for U.S. tax incentives such as the 45Z clean fuel production credit (effective 2025) and the 45Q carbon sequestration credit, e-fuel projects must demonstrate additionality (using new renewable energy rather than diverting existing clean power), geographic and temporal matching between electricity generation and hydrogen production, and low lifecycle emissions. The European Union’s ReFuelEU Aviation mandate similarly requires that e‑kerosene producers use additional renewable electricity and captured CO₂ . These rules add complexity and can delay projects if compliance frameworks are not well understood.

A quick framework for investors

Evaluating e-fuel opportunities requires integrating technical, economic and sustainability considerations. The following framework can help investors assess project viability:

1. Feedstock reliability and sustainability. Determine whether the project’s primary inputs—ethanol, CO₂, water and renewable energy—are secure and sustainable. For bio‑derived pathways, evaluate land‑use impacts and lifecycle emissions. For e-fuels, assess local renewable resources, grid interconnection costs and the availability of high‑purity CO₂ from industrial sources.

2. Technology readiness and scale. Examine the technology readiness level (TRL) of electrolysers, synthesis reactors and carbon capture systems. Pilot plants (TRL 6–7) carry higher execution risk than commercial projects (TRL 8–9). Review whether the developer has demonstrated similar technologies at scale and whether key equipment suppliers are secured.

3. Cost structure and policy incentives. Build a levelised cost of fuel (LCOF) model that includes capital expenditure, electricity and feedstock prices, conversion efficiency, maintenance and financing assumptions. Incorporate tax credits (45Q, 45Z), grants and low‑carbon fuel standard (LCFS) revenues. Conduct sensitivity analysis on electricity prices and carbon credit values.

4. Offtake agreements and demand. Identify anchor customers (airlines, freight companies, maritime shipping) and assess the credibility of long‑term offtake contracts. Consider how blending mandates (e.g., the EU’s 1.2 % e‑SAF requirement from 2030) and voluntary corporate commitments drive demand. Evaluate the risk of oversupply if policy support weakens.

5. Supply chain and execution risk. Review the developer’s partnerships for renewable power, electrolysers, carbon capture, water sourcing and logistics. Evaluate permitting and regulatory hurdles, including environmental assessments, grid connection agreements and safety requirements. Examine the developer’s balance sheet and ability to finance cost overruns.

Next‑steps checklist for investors

• Conduct a feedstock audit. Map the availability and quality of potential feedstocks (ethanol, captured CO₂, renewable power and water) within your target region. Compare local resources against project requirements.

• Engage with policy experts. Stay informed about evolving regulations like the U.S. Treasury’s guidance on the 45Z credit, California’s LCFS updates and the EU’s ReFuelEU rules. Government incentives can make or break e-fuel project economics.

• Seek strong partnerships. Look for developers with proven track records and secured relationships with equipment suppliers, offtakers and CO₂ providers. Integrated projects that combine renewable generation, electrolysis and synthesis reduce coordination risk.

• Build flexibility into project design. Consider modular plant designs that can be expanded as markets develop and costs fall. Explore hybrid pathways—such as blending ethanol‑derived SAF with e‑kerosene—to hedge against feedstock volatility.

• Focus on verifiable sustainability. Demand robust lifecycle assessments, third‑party certification and transparent carbon accounting. Projects that fail to meet sustainability thresholds may lose access to incentives and face reputational risk.

Frequently asked questions

What differentiates e-fuels from other sustainable aviation fuels? E‑fuels are synthetic hydrocarbons produced from renewable electricity, water and captured CO₂. They have unlimited feedstock potential because they do not depend on biomass; however, they require vast amounts of clean power and high‑purity CO₂. In contrast, bio‑SAF pathways rely on waste fats, oils and agricultural feedstocks, which are limited and subject to land‑use pressures.

Are e-fuels truly carbon neutral? When produced using additional renewable power and CO₂ captured from the atmosphere or sustainably produced biogenic sources, e-fuels can achieve 90–100 % lifecycle emissions reduction relative to fossil jet fuel. Residual emissions stem from plant construction, distribution and non‑CO₂ climate impacts (e.g., contrails). Projects must implement stringent carbon accounting to claim full benefits.

Is there enough CO₂ to supply large‑scale e-fuel production? U.S. ethanol plants produce about 48.7 million tonnes of CO₂ per year, less than 1 % of total U.S. emissions. Capturing CO₂ from ethanol, ammonia and steel plants can support initial e-fuel deployment, but scaling to hundreds of millions of tonnes will require widespread carbon capture and storage infrastructure, direct air capture and carbon transport networks.

How do current costs compare to conventional jet fuel? E‑kerosene currently costs around €5 per litre—up to ten times the price of Jet A fuel. Costs are expected to fall as electrolyser prices drop, renewable electricity becomes cheaper and conversion efficiencies improve, but e-fuels are unlikely to reach price parity without policy support and carbon pricing.

What about water consumption? Electrolysis consumes about 9 L of water per kilogram of hydrogen, and overall water use can reach 20–30 L per kilogram of hydrogen when purification and cooling are considered. While this is similar to or lower than the water demand of fossil hydrogen, investors should ensure projects have access to sustainable water sources and incorporate recycling.

Sources

1. Global supplies of used cooking oil (UCO) are estimated at 3.7 billion gallons in 2022 and expected to rise to 5–10 billion gallons by 2030; UCO prices are volatile and feedstock availability constrains bio‑based SAF.
2. Vegetable‑oil‑based SAF requires large land areas; the EU estimates that bio‑SAF production would need around 5 % of the bloc’s arable land for energy crops.
3. The AtJ pathway uses plentiful ethanol feedstock—global ethanol production reaches around 30 billion gallons—and LanzaJet’s Freedom Pines facility produces nine million gallons of SAF per year.
4. U.S. ethanol plants generate 42–49 million tonnes of CO₂ annually; only about 5 % is sold, leaving a large stream available for e-fuel synthesis.
5. Pairing waste CO₂ from ethanol plants with surplus renewable power could halve e-fuel costs; analysts project surplus renewable electricity could supply most U.S. jet fuel demand by 2050.
6. LanzaJet’s Freedom Pines plant (Georgia) produces nine million gallons of SAF and one million gallons of renewable diesel per year and is a key U.S. demonstration of the ethanol‑to‑jet pathway.
7. ETFuels’ Rattlesnake Gap project in Texas will use 500 MW of wind and solar power to produce 120,000 tonnes of e‑methanol per year, while sister projects target similar capacities.
8. HIF Matagorda in Texas will be the world’s first large‑scale e-fuels facility, producing 1.4 million tonnes of e‑methanol per year, recycling 2 million tonnes of CO₂, deploying 1.8 GW of electrolysers and investing about US$7 billion.
9. E‑fuel production requires 0.8 kg of hydrogen and 3.1 kg of CO₂ per kilogram of e‑kerosene, and hydrogen production via electrolysis consumes 50–56 kWh of electricity and roughly 20–30 L of water per kilogram.
10. The PtL pathway’s conversion efficiency is only 20–30 %, meaning 3–5 units of renewable electricity are required to produce 1 unit of fuel energy.
11. Current e‑kerosene costs are about €5 per litre, 4–10 times the price of conventional jet fuel, and the capital cost of e‑kerosene plants ranges from $500–1,200 per tonne of annual capacity.
12. Europe’s ReFuelEU Aviation mandate requires suppliers to blend 1.2 % e‑SAF by 2030 and increases to 35 % by 2050; despite numerous projects, none has reached final investment decision.