US biomethane sellers are increasingly looking to Japan and Singapore for niche opportunities in the year ahead, as policy roadblocks hinder demand closer to home.
Japanese gas utilities are targeting a 1pc share of renewable methane sales by 2030 amounting to around 180mn Nm³/yr. While they are mostly targeting e-methane made from low-carbon hydrogen, the relatively lower cost and abundance of US biomethane makes it an attractive bridge for companies trying to navigate the energy transition.
Osaka Gas has signed an agreement with BP subsidiary Archaea Energy to procure 26,000 Nm³ of biomethane from landfill gas that will be liquefied at the Freeport LNG terminal along the US Gulf Coast and shipped to Kansai. More deals between Japanese utilities and US biomethane producers are likely.
Singapore launched a 300MW biomethane import trial in September and opened further applications in December for at least 200MW of new data center capacity, of which at least 50pc should powered by "eligible green energy pathways" including biomethane.
But these are relatively slim pickings against a backdrop of US regulatory delays that may extend well into 2026.
Slow horses
While biomethane was incorporated into the new 45Z federal tax credit, offering a sliding subsidy scale depending on carbon intensity, specific guidance on how negative emissions would be treated remain elusive.
While the Treasury Department submitted a proposal to the White House in December, regulators could spend months writing the final rules. Changes to the 45Z tax credit passed into law this summer "may" allow fuels from animal manure to claim negative emissions in future years, but that treatment still needs final sign-off by regulators.
A similar story is playing out with the US Environmental Protection Agency's (EPA) renewable fuel mandates for 2026 and 2027, for which market participants may now have to wait until the first quarter next year.
Biomethane makes up the vast majority of program credits in the cellulosic D3 Renewable Identification Number (RIN) category, and EPA initially proposed revising down the 2025 requirement to 1.19bn RINs from 1.38bn and setting 2026 and 2027 requirements at 1.30bn and 1.36bn RINs, respectively.
The less-ambitious mandates reflect what the EPA sees as the market reaching a saturation point. Biomethane made up 86pc of all on-road fuel used in natural gas vehicles in 2024, according to industry association The Transport Project. Usage is closer to 97pc in California, the largest US market, where the fuel benefits from additional Low Carbon Fuel Standard credits.
Some data suggest that EPA is underestimating future consumption growth, providing fodder for inevitable future court cases about the legality of these cellulosic targets. Industry has already sued the agency over retroactively slashing the 2024 target by 7pc, citing a lack of supply. Indeed, revised RIN data up to October 2025 shows cellulosic generation could be on track to exceed the original 1.38bn target.
More natural gas fueling stations are also being built and could reach 1,400 going into 2026, the Transport Project said.
Still, growth in the natural gas vehicle fleet and fueling stations has paled in comparison to renewable natural gas (RNG) supply growth, which has averaged around 24pc/yr since 2015, according to EPA.
Compressed natural gas dispensers thus have more power to negotiate with producers, who have reported being asked for 30pc of the D3 RIN value — up from around 20pc previously — to pump the gas, as well as demanding a similar cut of the 45Z credit.
This is having a knock-on effect for suppliers seeking alternatives in voluntary sectors, where buyers are more price sensitive than those in mandatory markets and can drive a harder bargain.
Prices of Renewable Thermal Certificates (RTCs) — the environmental attributes associated with biomethane — have therefore failed to keep up with D3 RINs, falling from 60pc of their value in September to 50pc in December.
Sellers are worried that even if RIN prices recover in early 2026 once the regulatory haze clears, a corresponding rise in RTCs may not materialize because of persistent oversupply.
Several planned RNG projects have now been put on the backburner as a result, and producers are being forced to think creatively about accessing international markets. But the policy pendulum has swung away from them in many of those markets.
One battle after another
Many had pinned hopes on the International Maritime Organization adopting decarbonization targets for shipping in October, but the delay for at least a year could slow biomethane adoption in this area.
EU member states imposing stronger Renewable Energy Directive III mandates for next year will fuel biomethane demand in the region. But many EU members, including Germany, are stipulating connection to the EU grid for imports.
This aligns with conditions that will be imposed under the Union Database, the oft-delayed mandatory traceability tool for renewable fuels into the EU that is now targeted for a summer 2026 launch. While talks are ongoing to allow cooperation frameworks for product arriving from outside the bloc, progress so far has been slow.
Protectionist measures could also hit US exporters closer to home. Canada is inviting feedback on whether to implement a credit multiplier for domestic fuel under its Clean Fuel Regulations program to help producers combat the 45Z and RIN incentives south of its border.
A faint silver lining for sellers in 2026 does come at the state level, with New Mexico set to start its own low-carbon fuel standard scheme in April, which will boost RNG incentives in transport.
But New Mexico's biomethane demand will remain relatively small. The industry is pinning its hope on Asian demand — and further lobbying in Washington — to recover from the bruises suffered in 2025.
