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Latest natural gas news
Browse the latest market moving news on the global natural gas industry.
Viewpoint: RIN market awaits US policy clarity
Viewpoint: RIN market awaits US policy clarity
New York, 2 January (Argus) — US renewable fuel credits have traded in a narrow range for months but are likely to break out soon, when President Donald Trump's administration provides more clarity on incentives in the new year. Under the Renewable Fuel Standard, US oil refiners and importers must annually blend different types of biofuels or buy Renewable Identification Number (RIN) credits from those that do. The RIN market is closely watched by producers and marketers of biofuels such as ethanol, biodiesel and renewable natural gas, since higher credit prices make blending economics more attractive. Policy shifts supported RIN prices in 2025, including new tax credit rules that slashed subsidies for many fuels and encouraged the use of scarcer low-carbon feedstocks, as well as a plan Trump administration plan to require record-high blending during the next two years and to halve RIN credits for foreign fuels and feedstocks. Following the release of that proposal in June, values for current-year ethanol D6 and biomass-based diesel D4 credits rose to their highest levels since September 2023. RIN traders anticipated more expensive input costs, as reflected in a widening soybean oil-heating oil spread, hurting credit generation at the same time as the Trump administration moved to mandate more blending — the perfect storm for rising prices in 2026. But uncertainty over other policies has limited RIN credit growth more recently. Since October, current-year D4 and D6 credits have closed each session between 100¢/RIN and 110¢/RIN, rare for markets that are prone to frequent volatility. The government's unclear approach to exemptions from the biofuel blend program — which eligible small refiners can request at any time for any year — is one wrinkle. During Trump's first term, officials granted small refinery exemptions en masse, injecting a burst of added supply into the RIN market that sank credit prices and made it easier for refiners to reach their targets. Last summer, the Trump administration granted dozens of full and partial exemptions, and more requests are pending, raising fears of a similar supply shock. But the potential weakness comes with a parachute. The Trump administration has floated making oil companies without exemptions bring more biofuels to market over the next two years to offset recent waivers. The plan has divided the industry and kicked off a last-minute lobbying campaign, with oil majors hoping to avoid picking up the slack and biofuel advocacy groups warning of pain for farmers if biofuel demand lags. So the market is at a standstill, with RIN traders guessing as to future policy. Strong mandates, penalties for foreign feedstocks and compensating for recent exemptions would support prices. But shifts in policy — coupled with guaranteed higher tax breaks for crop-based fuels in 2026 — threaten the opposite. Even if administration officials stay quiet until regulations are finalized, the calendar could provide RIN traders with an important signal. The Trump administration last told a court that it expects to finalize updates to the biofuel blend program in first-quarter 2026 , meaning the industry will start the year lacking clarity on how many biofuel gallons — and what type — they should bring to market. The delay is important because US regulators have been more cautious in the past when finalizing retroactive biofuel mandates to avoid legal scrutiny. But the biggest price moves will ultimately depend on final policy clarity. By Matthew Cope and Cole Martin Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.
Viewpoint: Bruised US biomethane sellers pivot to Asia
Viewpoint: Bruised US biomethane sellers pivot to Asia
Houston, 30 December (Argus) — 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. By Ammo Parmar Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
ANP revises Brazil natural gas pipeline tariffs
ANP revises Brazil natural gas pipeline tariffs
Sao Paulo, 29 December (Argus) — Brazil hydrocarbons regulator ANP today approved a revised natural gas tariff regime that clarifies capacity contracting rules and establishes a stable pricing mechanism for entry-exit transport operators. ANP, in its extraordinary board meeting on 29 December, also refined the weighted average cost of capital (WACC) to provide updated guidelines on how capital returns will be calculated, promising greater predictability in the 2026–2030 cycle. A double-payment safeguard will enhance tariff fairness by ensuring operators are compensated only once per asset, addressing longstanding sector concerns, according to ANP. The new tariff framework sets conditions for contracting capacity and defines pricing for entry and exit points in the gas transport network. ANP updated the methodology for calculating the WACC for the next regulatory cycle, which will govern returns on regulated investments from 2026 to 2030. A mechanism to prevent double remuneration for pipeline assets was also approved. This involves assessing the depreciation stage of infrastructure to determine the regulatory asset base and allowed returns. ANP says the changes aim to align tariffs with actual costs and improve transparency in the sector. These decisions may shape Brazil's gas transport market in 2026, by giving clearer rules for operators and more predictability for shippers. By Betina Moura Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Viewpoint: Biogas growth uneven, shipping drives 2026
Viewpoint: Biogas growth uneven, shipping drives 2026
London, 22 December (Argus) — Europe's biomethane market faces uneven growth in 2026, with numerous unsolved policy hurdles and as adoption of the EU's revised renewable energy directive (RED III) reshapes national compliance frameworks. Shipping demand will remain a key driver, particularly for certified subsidised product. RED III's overall 2030 target gives EU member states the option to reduce greenhouse gases (GHGs) by 14.5pc, or reach a 29pc renewable energy share. RED II only required countries to reach a 14pc renewable energy share. Some states have already transposed RED III, including the Netherlands and Germany , and pivoted incentive schemes to reward fuels on a GHG reduction basis. This is setting up biomethane with low or negative carbon intensity (CI) as a fuel of choice for suppliers obligated to comply with the regulation in the Netherlands, where previously it lagged behind cheaper, energy-intense biofuels. Another EU regulation that favours biomethane use is FuelEU Maritime, which came into effect in January 2025 requiring shipowners to reduce fleet emissions by 2 pc/yr in 2025 and 2026. Over-compliance can be sold under pooling schemes — which have proven profitable for bio-LNG bunkering. The mandate became a major market price driver for renewable gas guarantees of origin (RGGOs) — certificates issued to companies producing gas made from non-fossil fuel sources — and this should continue into 2026. New schemes, either under RED III or domestic obligations, that will come into effect in 2026 will compete with maritime demand for supply. Most 2026 Dutch and Danish supply has already been sold to the maritime sector. Growing Netherlands As well as a pivot to GHG-based compliance with a new ERE ticket system under RED III, the Netherlands began work on a Green Gas Blending Obligation in November. While implementation before late 2027 seems unlikely, progress should boost RGGO forward pricing. Dutch biomethane liquidity could be bolstered if the government approves mass-balancing , a method to track and verify biomethane when it is injected into the gas grid system and becomes indistinguishable from conventional gas. A motion was proposed in parliament in November, but a recent government response indicates this is unlikely. Bio-LNG must be unsubsidised, certified and physically delivered to qualify for ERE tickets, otherwise it will be treated with a fossil gas CI of 94g CO2e/MJ when calculating a fuel supplier's overall mandate level. Steady Germany, France Germany will remove double-counting for waste-based biofuels under its GHG reduction quota (THG) in 2026, but biomethane should remain the cheapest compliance route for fuel suppliers, as rising mandates will support demand. Most German imports come from the UK or Denmark. The former may benefit from Danish prices inflated by maritime demand, despite questions about UK eligibility with German schemes. France's biogas production certificate (CPB) blending mandate starts in January, which should significantly boost domestic demand. But the country has delayed its RED III transposition , which includes a new GHG-based IRICC ticket system, to 2027. The current energy-based TIRUERT transport ticket system will remain in place for a year, limiting transport-sector uptake. It is unclear if IRICCs can be generated from biomethane in 2027, but 3pc renewable gas obligations for transport will start in 2028, increasing thereafter. Cross-border trade and bio-LNG bunkering should remain limited. French biomethane can only be exported as an ex-domain cancellation , the cancellation of RGGOs in one country's registry for use in a different country. This carries risk to buyers, as ownership is not necessarily transferred. Subsidised biomethane cannot be liquefied at French LNG terminals for use outside the country. French bio-LNG must be exported via mass-balancing to other terminals in the EU, for use under FuelEU Maritime. Uncertain UK The UK's access to EU markets hinges on access to the Union Database for gaseous Biofuels (UDB), now targeted for launch by end-summer 2026. Uncertainty about third-country treatment could restrict EU trade — a critical issue given the UK exported more than half its RGGOs in the first three quarters of 2025, mostly to Germany, Norway and Switzerland. The UK is consulting on replacing volume-based RTFC tickets with a GHG-based system, but any changes would not be enacted until 2027. Overall in Europe, biomethane remains well positioned in GHG-based systems, but policy implementation delays will probably slow overall market growth. The Netherlands, Denmark and Germany should remain anchors for European pricing, and Spain should consolidate its role as a maritime hub. But several countries risk lagging behind without RGGO registries, export hub access, policy incentives and subsidy reform. By Madeleine Jenkins Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
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