E-methane: a promising low-carbon alternative to natural gas?

Natural gas and liquified natural gas (LNG) are critical to decarbonisation, bridging the transition from coal to renewables and ensuring the continuity and reliability of baseload power. Consequently, demand for natural gas and LNG is projected to rise 11% from 3,900 bcm to 4,340 bcm by 2050. This creates an opportunity for low-carbon alternatives as governments push to reduce emissions.  

The biomethane market, which saw a 34% capacity increase from 2022 to 2023, shows promise, but still relies on subsidies and faces challenges when it comes to feedstock availability, feedstock logistics, pricing and regulatory compliance. E-methane, however, produced using captured carbon and green hydrogen from renewable electricity, presents itself an alternative.  

The key advantage of e-methane over other derivatives, such as ammonia and methanol, is that it is a direct drop-in fuel, requiring no new infrastructure. It can be integrated into existing pipelines, liquefaction terminals, LNG carriers, floating storage regasification units (FSRUs), gas boilers and more. However, even in the best-case scenario today, it remains at least four times more expensive than natural gas ‒ a key hurdle, despite potential cost reductions and policy support.  

In a recent report ‒ and ahead of the publication of a new model for calculating the levelised cost of e-methane ‒ Wood Mackenzie analysts explored the decarbonisation potential of this hydrogen derivative as an alternative to fossil natural gas, focusing on chemical methanation to evaluate its current costs and technological maturity. To receive a complementary extract from the report, fill in the form, and read on for a brief outline.  

Big in Japan (and Europe) 

The emerging industry is set to be fuelled by Japanese mandates and European Union (EU) emission policies. Japan has been the frontrunner in driving demand for e-methane, looking to capitalise on its extensive LNG import infrastructure. It aims to replace 1% of city gas volume with e-methane from 2030 and increase the replacement rate to 90% by 2050.  

Japanese city gas companies, therefore, are looking to procure gas from overseas. North America has responded, boasting the highest planned production capacity, supported by 45V and 45Q tax credits for hydrogen production and the industrial use of captured carbon. In a consortium with Japanese utilities Toho Gas, Tokyo Gas and Osaka Gas, as well as Mitsubishi, Sempra is developing the ReaCH4 project in Louisiana, which plans to produce 130 ktpa of e-methane for export to Japan from 2030. 

With a primary focus on reducing natural gas demand for heating, developers in Finland, meanwhile, have taken up the charge to pursue e-methane production as a viable alternative. 

Thanks to €45 million in funding from European Hydrogen Bank Round 1 and a separate €45 million grant from the EU’s innovation fund, Nordic Ren Gas has a project portfolio solely focusing on e-methane production. It has six projects under development across southern Finland, with an expected start date of 2027. Gas and biogas supplier Gasum has signed an agreement to offtake and supply 960 GWh/y of e-methane (around 62 ktpa HHV) to the Finnish gas grid.  

Netherlands-based Tree Energy Solutions (TES) is promoting e-methane for its infrastructural compatibility. TotalEnergies is studying the Live Oak e-NG project with TES to produce up to 200,000 tons of e-methane per year by 2030. TES’s Wilhelmshaven Hub in Germany has secured a 20-year exemption from BNetzA, the German Federal Network Agency, allowing it to allocate 90% of capacity via long-term contracts. 

Cost remains a key issue 

E-methane production is not completely straightforward. It relies on continuous CO2 supply, unlike ammonia, which can be produced anywhere with electricity, including isolated energy-rich regions. Added to that, low overall process efficiency has led to high costs, limiting participation and leading to fewer announcements than for other hydrogen derivatives. Announced global capacity currently stands at 2.5 Mtpa of hydrogen equivalent, translating into 5 Mtpa of e-methane. The total operational and under-construction capacity of e-methane remains at just 13 ktpa.  

To date, e-methane production has been limited to pilot-scale projects, making it difficult to estimate commercial production costs. Although methanation technology is mature, its cost accounts for a minimal proportion of overall e-methane levelised costs. Cost reductions will generally come from two sources: learning-curve reductions, where efficiencies and technology design improve with experience, and economies of scale, where larger facilities reduce per-unit production costs.  

Taking into account 45V and 45Q tax credits, the US Gulf Coast currently produces the most competitive e-methane, with costs as low as US$20/MMBtu. China is second, thanks to its extremely cheap power, resulting in a cost range of US$30-45/MMBtu. In European countries that have shown interest, the costs exceed US$50/MMBtu. By comparison, Wood Mackenzie’s long-term Northwest European hub prices average US$10/mmbtu. 

Our price forecasts suggest that e-methane will reach cost parity with landed LNG in Japan only under specific conditions. These include rising carbon costs and heavily subsidised green hydrogen production.  

Learn more 

To get more insights into the future of e-methane and to download an extract from our recent report, ‘Future of natural gas: decarbonising with e-methane', fill out the form at the top of the page.