Natural gas
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Natural gas has been fuelling industrial and economic growth across developed and developing countries. Its usage is set to increase as it is also being considered as a low-carbon fuel that can help make the transition to a no-to-low-carbon economy. Argus is your irreplaceable source of price information, news, expert analysis and fundamentals data for international natural gas markets.
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Latest natural gas news
Browse the latest market moving news on the global natural gas industry.
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.
Energy Transfer halts plans for Lake Charles LNG
Energy Transfer halts plans for Lake Charles LNG
Houston, 18 December (Argus) — US midstream firm Energy Transfer is suspending development of its planned 16.5mn t/yr (2.2 Bcf/d) Lake Charles LNG export terminal in Louisiana to focus on natural gas pipeline expansions, the company said today. The pivot allows the company to reallocate capital to gas pipeline projects that provide "superior risk/return profiles", Energy Transfer said. The company separately said it will increase the capacity of its planned Desert Southwest expansion of the Transwestern pipeline, allowing it to move more gas from west Texas' Permian basin to the southwestern US. The decision to scrap Lake Charles LNG follows a month of dissonance from company executives about moving forward with the facility. Energy Transfer co-chief executive Mackie McCrea told investors in early November that the company would not be able to reach a final investment decision (FID) until it sold off 80pc of equity shares in the project. But Amy Chen Davis, vice president of Lake Charles LNG, told an industry event on 10 December that the company was in talks with potential partners and would reach a final decision in early 2026. The company said earlier this year it planned an FID by the end of 2025. The midstream firm has sought for years to convert the existing Lake Charles import facility into an export terminal. Shell signed on with a 50pc stake in 2019 but pulled out the following year as part of cost-cutting measures during the Covid-19 pandemic. McCrea had signaled to investors that the company was being cautious with entering the LNG export industry. "When you're chasing billions of dollars in projects, several of which we've already announced, we've got to be careful stepping out on something like this," McCrea said on 5 November. "We're not an LNG company like we compete with. We're a pipeline company that has a regas facility converting part of it to LNG." Investor MidOcean Energy had signed a preliminary agreement to fund 30pc of Lake Charles LNG's construction costs in exchange for 30pc of offtake, but the firms never finalized the deal. Suspension of the project also may set back the efforts of Saudi Aramco, which holds a 49pc stake in MidOcean, to develop an LNG portfolio. MidOcean has a share in Peru's 4.45mn t/yr Pampa Melchorita LNG export plant and the Shell-led 14mn t/yr LNG Canada export terminal in British Columbia. Pipeline project in focus Meanwhile, Energy Transfer said it will upsize capacity on the Desert Southwest expansion. The company said it will increase the expansion's capacity by 800mn cf/d to 2.3 Bcf/d to satisfy additional demand in the southwestern US. Energy Transfer reached an FID on Desert Southwest in August. The expansion is one of several projects working to increase gas transportation capacity out of the Permian, where a steady increase in crude-driven activity — and commensurate rise in associated gas output — has outpaced the increase in gas takeaway capacity. This has created a local gas supply glut and some of the lowest gas prices in the US. By Tray Swanson Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Romanian gas demand to rise on higher power-sector use
Romanian gas demand to rise on higher power-sector use
London, 16 December (Argus) — Romanian gas demand is expected to increase next year as a result of new gas-fired power capacity starting up, although the extent of demand growth could be limited by project delays. Romanian gas consumption averaged 257 GWh/d on 1 January-14 December, below full-year 2024 demand of 283 GWh/d, and only slightly above a historic low of 256 GWh/d in 2023 ( see graph ). Romanian industrial users and power generation have accounted for 24pc of gas consumption so far this year, with 76pc coming from residential demand. Romanian gas demand had been increasing until the energy crisis of 2022, supported by growing household grid connections and coal-to-gas switching in power generation. Romania's ability to become net exporter following the commissioning of the Black Sea Neptun Deep field will depend on where domestic consumption stabilises. This will determined by the buildout and utilisation of gas-fired power plants and industrial gas consumption. Romania plans to replace coal-fired power plants with new gas-fired combined-cycle gas turbine (CCGT) plants and cogeneration units, which may support domestic gas needs in the next few years. Romanian gas-fired output has totalled 8.9TWh this year, accounting for 20pc of power generation, down from 10.3TWh for 2024. The country planned to decommission 3,780MW of coal and lignite-fired generation capacity by the end of 2025, before phasing out these fuels from the power mix by 2032. But Romania has renegotiated with the EU to postpone the coal phase-out until the end of 2029 because of slow progress building gas-fired plants. This will ensure the security of the domestic energy system and guarantee the country avoids blackouts during the winter, energy minister Bogdan Ivan said. Under the new schedule, Romania will have 900MW of lignite-fired units operational until the end of 2029. Coal has made up 14pc of the generation mix so far this year, unchanged from a year earlier. Romania has not added any thermal capacity in recent years, but several CCGT units are expected to be commissioned next year. The start-up of the long-awaited 430MW Iernut CCGT — previously expected at the end of this year — has been pushed back to the second quarter of 2026. The 1.75GW Mintia CCGT is due to come on line by the end of next year, while a 53MW gas-fired combined heat and power plant in Constanta, southeast Romania, is scheduled to begin operations by June 2026. An 850MW CCGT plant is also planned at Isalnita. These projects could boost combined power-sector gas demand by over 4bn m³/yr in 2026, Argus estimates, assuming they are running at maximum capacity. But the Isalnita project may struggle to come on line next year, while the other projects could experience further delays. And Romania's reliance on gas for power generation is likely to increase further in the coming years because a 700MW unit at the Cernavoda nuclear plant is scheduled to shut down for modernisation in 2027-29. But Romania has also been expanding renewable capacity, which could limit uptake of gas in power generation. The country added 1.2GW of solar capacity over the first 11 months of 2025, up from 303MW in 2024. Total solar capacity stood just above 3GW at the end of November, while solar output has averaged 327MW so far this year, up by 75MW from 2024. But just 41MW of wind capacity has been added so far this year, down from 69MW in 2024. Azomures' gas demand could rise next year Fertiliser producer Azomures, Romania's largest gas consumer, restarted part of its production in July after 11 months of downtime, and the firm may restart nitrogen production next year in response to an anticipated increase in import prices caused by the EU's Carbon Border Adjustment Mechanism and lower natural gas costs, according to a market participant. Romanian industrial output fell by 0.5pc year on year in January-October, the national statistics office said on Monday. The European Commission expects Romanian GDP to grow by 0.7pc this year, 1.1pc in 2026 and 2.1pc in 2027, it said on 17 November. This could support industrial gas demand growth in the coming years. Domestic onshore production is projected to decline towards 2035, but output from Neptun Deep — owned 50:50 by domestic firm Romgaz and Austrian OMV — is scheduled to start in 2027. The project aims to increase the country's gas output to 18bn-20bn m³/yr from 8bn-10bn m³/yr at present, bringing "Romania full import independence and even net-export status from 2027", the government has said. Romgaz has received government approval to assess a potential acquisition of Azomures. Romgaz could provide access to reliable supply, potentially changing the market position of the chemical producer. Assuming Azomures operates at full capacity, Romanian gas consumption could rise by 1.2bn m³/yr, according to grid operator Transgaz ( see table ). By Victoria Dovgal Sources of Romanian gas demand growth bn m³/yr Project Demand 1.75GW Mintia power plant 2.5 850MW Isalnita CCGT 0.8 475MW Turceni CCGT 0.8 430MW Iernut CCGT 1.0 Azomures fertiliser plant 1.2 Piatra-Neamt chemical plant 0.8 Household sector 3.0* * target — Transgaz Romanian gas consumption TWh Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Australia’s Beetaloo reaches FID on shale gas pilot
Australia’s Beetaloo reaches FID on shale gas pilot
Sydney, 12 December (Argus) — Australian shale gas developer Beetaloo Energy has made a final investment decision to build its 25 TJ/d (668,000 m³/d) Carpentaria pilot project in the Beetaloo subbasin in Australia's Northern Territory (NT), ahead of first gas targeted for mid-2026. Civil construction and upgrade works on the Carpentaria plant have already started, chief executive Alex Underwood said on 11 December, which involves the tie-in of up to 10 wells located in exploration permit 187. The decision comes after the firm this week received NT government approval to sell appraisal gas from Carpentaria. This is the second pilot project to reach FID in the untapped shale gas basin after Tamboran Resources' 40 TJ/d Shenandoah South pilot project, also targeting first appraisal gas in mid-2026. The NT government has agreed to purchase the entirety of gas from both projects via an ex-field take-or-pay basis, to supply government-owned Power and Water Corporation. If the basin's reserves prove economically viable Tamboran is eyeing LNG exports in the longer-term, potentially via Australian independent Santos' Darwin LNG project . By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.