LNG
概要
LNGは、投入コストと炭素排出の両方を管理するのに役立つため、重要な原料としての位置を確立しています。重工業ユーザーによるネットゼロ目標達成の推進は、LNGの使用方法と使用場所に新たな局面をもたらしています。全体として、使用量は増加すると予想され、最も成長率の高い化石燃料になると予測されています。
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Browse the latest market moving news on the global LNG industry.
India’s Petronet offers lower LNG regas rates
India’s Petronet offers lower LNG regas rates
Mumbai, 23 December (Argus) — India's state-run LNG terminal operator Petronet LNG has offered over 25pc discount on regasification tariffs to fellow state-run gas distributor Gail at the expanded capacity of the Dahej LNG terminal on the west coast, which is set to be commissioned in 2026, sources with knowledge of the matter told Argus . Petronet has offered to lower the regasification tariff for Gail at 52.05 rupees/mn Btu ($0.58/mn Btu) from the current Rs66.06/mn Btu at the 5mn t/yr expanded capacity of Dahej — which is set to be commissioned in March 2026 . The lower-than-expected rate compares with Rs69.36/mn Btu projected for 2026 based on the 5pc annual rise in regas tariff that Petronet charges its customers for Dahej Terminal. Regas tariffs stood at Rs62.91/mn Btu in 2024. Petronet also charges around Rs114.5/mn Btu at its 5mn t/yr Kochi terminal to the long-term customers, which may be the highest regasification tariffs globally. State-run Gail is understood to have booked 1.5mn t/yr of LNG utilisation out of the 5mn t/yr expanded LNG terminal capacity at Dahej, sources said. Of the 17.5mn t/yr Dahej terminal capacity, 8.5mn t/yr is dedicated to long-term back-to-back contracts with QatarEnergy. The remaining 8.25mn t/yr is sold on a tolling basis to LNG importers including Gail, GSPC, IOC, BPCL, and Torrent Power. Petronet LNG is also reported to have offered customers a further reduction in regasification rates of up to Rs30/mn Btu from 2028 onwards, when its long-term LNG supply contract renewal of 7.5mn t/yr with QatarEnergy kicks in , sources added. Neither Petronet nor Gail responded to Argus queries for confirmation. Once implemented, LNG importers from 2026 onwards are expected to bear only the cost of natural gas plus applicable customs duty and regasification tariffs, as most supply contracts are on a delivered basis, eliminating shipping costs. Government criticism The tariff reduction likely follows sharp criticism Petronet received from the gas regulator, the Petroleum and Natural Gas Regulatory Board (PNGRB), in its December 2024 report, which stated that Dahej's "terminal capacity expansion (from 5mn t/yr in 2004 to 17.5mn t/yr currently) should have led to a reduction in regasification costs." LNG importers in the country have also complained that Petronet LNG and privately-owned Shell charge some of the highest regasification rates in the world to regasify LNG. However, following the criticism, Petronet described the regasification tariff as "reasonable" . This was later followed by the regulator, PNGRB, directing LNG terminal operators in the country to list current regasification and truck-loading charges on their websites to bring transparency to terminal operations and boost utilisation. The is set to increase competition among other offtakers like IOC, GSPC, BPCL, AMNS, and Torrent Power to also negotiate similar deals with Petronet. It may also add pressure to neighbouring terminals — privately-owned Shell's 5mn t/yr Hazira terminal and HPCL's 5mn t/yr Chhara terminal, both struggling to reach even 50pc utilization — to cut their regasification rates, traders said. Shell and HPCL are actively allowing third party access to their terminal, unlike Mundra, Dabhol, and Ennore. Utilisation Capacity utilisation at the Dahej was 92pc during April-October, the highest in the country, oil ministry data show. The Dahej terminal's high utilization justifies the reduction in regasification tariff, however few scepticisms also have raised on Petronet's' decision to put Gopalpur terminal without anchor customers and proper pipeline connectivity. The management aims to complete the 5mn t/yr Gopalpur terminal project by 2028. Market participants fear Gopalpur terminal could face challenges similar to Kochi terminal, which has struggled to achieve even half of its capacity utilization for its most of the operational period since 2013. Kochi's utilisation stood at 24pc during April-October this year, oil ministry data show. The terminal achieved its highest LNG regasification at 17 trillion Btu (0.35mn t) during July-September quarter, up 21pc on the year and 31pc higher on the quarter, the management said in its latest earnings press conference in November. Nevertheless, the lower regasification rates are expected to boost India's LNG imports and natural gas usage, supporting government plans to make the country a gas-based economy, with the share of natural gas in its primary energy mix targeted to rise to 15pc by 2030, from around 7pc in 2024. By Rituparna Ghosh Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Viewpoint: US, European LNG spread may narrow in 2026
Viewpoint: US, European LNG spread may narrow in 2026
Houston, 22 December (Argus) — The spread between US and European LNG prices will likely narrow further in 2026, but forward prices indicate US LNG supply under long-term contracts will remain comfortably profitable in international spot markets until at least summer 2027 as a wave of new supply comes on line. A recent rally in the US natural gas market highlighted US LNG's tightening margins. The indicative long-term LNG contract price — 115pc of US benchmark Henry Hub plus a $3/mn Btu liquefaction fee — surpassed the Argus Gulf coast (AGC) spot fob price in early December for the first time in more than two years amid cold weather in the US, mild weather in Europe and high Atlantic basin freight rates. But the premium over the spot price was brief and caused no change to export schedules. The front-month Henry Hub contract quickly shed its gains on warmer weather, falling to $3.89/mn Btu on 16 December from a nearly three-year high of $5.29/mn Btu on 5 December. Prices hovered around $4/mn Btu through 19 December. The impact was solely on profit margins rather than fundamentals. Customers of US LNG facilities did not need to cancel cargoes under take-or-pay provisions because a profit incentive to maximize exports remained. Liquefaction costs are considered sunk, and the spread between Henry Hub and European LNG prices remained wide enough to more than cover shipping costs. Though rising exports may add to domestic pricing volatility during cold winter weather through the end of the decade, US and European gas futures today indicate long-term offtake from US LNG terminals will remain profitable until the summer of 2027, assuming freight rates of $80,000/d and a 50¢/mn Btu discount to the European benchmark TTF for northwest European deliveries. At that time, contracts with $3/mn Btu liquefaction fees could surpass delivered LNG prices in northwest Europe, though the arbitrage for US gas would remain open for contracts with lower fees (see chart) . Fees now range between $2.50-2.80/mn Btu for US supply coming on line toward the end of the decade. Contracts with fees on either end of that range remain below European LNG prices until summer 2029 and summer 2028, respectively, assuming freight rates of $80,000/d. But cargo cancellations are not always necessary when long-term US LNG contract prices surpass international prices. Terminal operators and their customers finalize annual delivery plans as well as upward and downward delivery tolerances before the start of each year, leaving less flexibility later in the year. If a customer wishes to cancel a cargo, they typically must notify the terminal up to two months in advance, which would likely only happen in an environment where the cost of 115pc of Henry Hub plus freight stabilizes above European LNG prices. The spread between Henry Hub and delivered European prices is wide enough to absorb freight costs through winter 2030-31. If an offtaker opts for a lower quantity in its delivery tolerance or cancels a cargo, the volume returns to the terminal operator, which could still market and sell the cargo on the spot market. This effectively shifts the seller of a cargo from the LNG customer to the LNG terminal operator. The likelihood of cancellations beyond 2027 may be higher in the spring and autumn shoulder seasons, when demand in Europe is typically lower. Depending on the previous winter, this may be more likely to occur in autumn, given the annual rebuild of Europe's underground gas inventories that begins in the spring. Additional liquefaction capacity has already helped tighten margins for US LNG since Europe's conflict-driven volatility in 2022 . The AGC fob's premium over the long-term indicative contract averaged $3.95/mn Btu through 19 December this year, down from $4.63/mn Btu, $5.37/mn Btu and $20.13/mn Btu in 2024, 2023 and 2022, respectively. But the anticipated convergence of US and European LNG is not guaranteed. Geopolitical conflict could disrupt existing trade patterns. And lower prices in Europe will be contingent on new LNG projects, led by the US and Qatar, maintaining their timelines, which are prone to delays from supply chain issues and workforce constraints. This would add upside risk to international prices and downside risk for Henry Hub if the delays are in the US. By Tray Swanson European LNG spot prices vs long-term US LNG $/mn Btu 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.
Japan's Niigata assembly backs Tepco's nuclear return
Japan's Niigata assembly backs Tepco's nuclear return
Osaka, 22 December (Argus) — Japan's Niigata prefectural assembly has supported its prefectural governor's decision to approve the restart of the Kashiwazaki-Kariwa nuclear reactors operated by utility Tokyo Electric Power (Tepco). The assembly passed a vote of confidence on Niigata governor Hideyo Hanazumi on 22 December. He had sought the assembly's judgement on his plan to authorise the restart of the No.6 and No.7 reactors at the Kashiwazaki-Kariwa, each with a capacity of 1,356MW. Hanazumi had previously indicated that he would step down if the motion was rejected. The motion was attached to a supplementary budget request of ¥31mn ($197,048) for the April 2025-March 2026 fiscal year, intended to support activities related to the restart of the Kashiwazaki-Kariwa nuclear plant. Hanazumi plans to meet Japan's trade and industry minister Ryosei Akazawa on 23 December to discuss the restart of the nuclear plant. The endorsement will allow Tepco to move towards restarting its reactors for the first time since they triggered the Fukushima-Daiichi nuclear disaster, after a powerful earthquake and tsunami in March 2011. The plant, which has remained off line since March 2012, is Tepco's sole nuclear station, after it scrapped the damaged Fukushima Daiichi and nearby Fukushima Daini plants. The Kashiwazaki-Kariwa plant comprises of seven reactors with a combined capacity of 8,212MW, of which the No.6 and No.7 units have cleared the stricter post-Fukushima safety inspections. Tepco has yet to file an application with the country's nuclear regulation authority (NRA) for screening of the five other reactors. The utility is also mulling scrapping the No.1 and No.2 reactors. Tepco is expected to prepare for the restart of the No.6 reactor first, given that the No.7 unit will be required to remain shut until August 2029 for the installation of anti-terrorism facilities. The No.6 reactor is expected to resume operations after clearing pre-use inspections, which typically last for three weeks to one month. This means that Tepco will be able to restart the No.6 reactor in January at the earliest. The return of the Kashiwazaki-Kariwa plant could be a milestone in Tepco's progress in nuclear power generation after the Fukushima disaster, with the No.6 unit marking Tepco's first reactor to be restarted after the disaster. Electricity from the nuclear plant will be sent to the Tokyo metropolitan area, with the nuclear plant — located in the Tohoku region — mitigating the risk of a power shortage in Japan's capital. A single nuclear reactor can produce 10 TWh/yr of electricity, and can save the company an estimated ¥100bn/yr, Tepco previously said. The return of the No.6 reactor is also expected to reduce CO2 emissions by around 3.3mn t/yr, it added. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
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