LNG
Overview
LNG's role as a key feedstock is well established as it helps manage both input costs and carbon emissions. Heavy industrial users' drive to achieve net zero targets has added a new dimension to how and where it is being deployed. Overall, its use is expected to increase and is tipped to become the strongest-growing fossil fuel.
At Argus, we expertly provide in-depth and reliable perspectives on the international LNG market. Our clients receive live access to critical data sets and analytics, comprehensive analysis and market-moving industry news. Our LNG service is the product of our market experts, who are based in all of the principal LNG trading hubs around the world.
Companies, trading firms and governments in 160 countries trust our data to support making more intelligent decisions, analysing situations, managing risk, facilitating trading and long-term planning.
Latest LNG news
Browse the latest market moving news on the global LNG industry.
TotalEnergies ends Papua LNG rebid phase: Correction
TotalEnergies ends Papua LNG rebid phase: Correction
Corrects headline and 'FID' to 'development forum' in last paragraph Sydney, 12 December (Argus) — New engineering, procurement and construction (EPC) contract offers have been received for the proposed 5.6mn t/yr Papua LNG project in Papua New Guinea (PNG), operator TotalEnergies said, following extensive design revisions for the delayed development. The firm is concluding the rebid phase after receiving new offers at reasonable costs, managing director of TotalEnergies EP PNG Arnaud Berthet told the PNG Resources and Energy Investment Conference in Sydney on 10 December. TotalEnergies relaunched EPC tendering late last year after previously estimated costs were considered too high for the project to proceed. The company expanded the contractor pool to include Chinese firms and reduced the gas pipeline diameter to 30 inches from 40 inches. This change increased the number of vessels able to perform pipelay, Berthet said, increasing competition, while it also routed the condensate pipeline west to a new floating storage and offloading vessel, reducing pipeline length. A development forum is planned for January-March next year, a legal requirement ahead of a final investment decision, which JV partner Australian independent Santos has previously signalled is likely in early 2026 . LNG sales and purchase agreements are under negotiation, and seven export credit agencies along with more than 30 commercial banks are interested in financing the project, Berthet said. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Japan’s Hokkaido approves Tomari nuclear restart
Japan’s Hokkaido approves Tomari nuclear restart
Osaka, 10 December (Argus) — Japan's Hokkaido prefecture has approved the restart of Hokkaido Electric Power's (Hepco) Tomari nuclear power plant, removing the final hurdle to restarting the first reactor in the northernmost prefecture since the 2011 Fukushima nuclear disaster. Hokkaido governor Naomichi Suzuki officially approved the restart of the 912MW Tomari No.3 reactor on 10 December, nearly two weeks after stating on 28 November that the use of nuclear power remains a practical option for the time being. His decision was supported by four local authorities — Tomari village, Kyowa town, Iwanai town and Kamoenai village — whose consent is also required to resume operations at the Tomari plant. Approval from local governments is essential before any nuclear reactor restart in Japan, even when reactors meet stricter safety standards designed to prevent a repeat of the Fukushima-Daiichi reactor meltdown following the 2011 earthquake and tsunami. The approval means the Tomari No.3 reactor is likely to restart once reinforcement work is completed, as the unit already received a safety clearance from Japan's nuclear regulation authority (NRA) in July. Hepco hopes to restart the reactor as early as possible in 2027. The Tomari plant is Hepco's sole nuclear facility, comprising the 579MW No.1 and No.2 reactors in addition to No.3 unit. The No.1 and No.2 reactors are still undergoing the NRA safety inspections. Hepco has been without nuclear power since May 2012, relying on thermal generation instead, which has increased costs. The utility consumed 1.78mn t of coal over April-September, up by 9.6pc from a year earlier, while oil usage edged up by 0.9pc to 3,884 b/d. LNG consumption fell by 61pc to 85,000t during the period, mainly because of maintenance at a gas-fired plant. Hepco expects household electricity rates under regulated tariffs to fall by around 11pc following the planned restart of Tomari No.3 reactor. For non-regulated tariffs, overall rates are projected to decline by an average of 7pc, including roughly 11pc for low-voltage customers and about 6pc for high- and extra-high-voltage users. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
LNG carrier headed for Boston on high spot gas prices
LNG carrier headed for Boston on high spot gas prices
Houston, 9 December (Argus) — A laden LNG carrier appears destined for a rare voyage to the 5.1mn t/yr Everett LNG import terminal near the US' Boston, likely attracted by high spot gas prices amid a prolonged cold snap in the US Northeast. The 174,000m³ Maran Gas Antibes , which loaded at Egypt's 7.2mn t/yr Idku terminal on 28 November, was sailing west across the north Atlantic, putting it on course to arrive at Everett LNG on 14 December at its current speed of 15 knots. The Everett LNG terminal is typically used only in winter. The New England region has scarcer pipeline capacity than elsewhere in the US, causing price spikes when its few interstate pipelines reach the limits of their operational capacity, as they regularly do in the region's chilly winters. New England spot prices have surged this month on elevated heating demand. The Algonquin Citygates index, a key indicator for New England spot prices, was $21.25/mn Btu on 8 December. The price averaged $21.51/mn Btu in the week that ended the same day, more than double the prior week. That was much higher than delivered LNG prices in northwest Europe, where the price for January delivery was $8.70/mn Btu on 8 December, though buyers into Everett would likely have to pay a premium because of the promptness of the requirements. The forecast indicates colder-than-normal weather will remain in New England through 16 December. The Maran Gas Antibes was initially headed for France's southern coast on 3 December, suggesting arrival at the 6.6mn t/yr Fos Cavaou terminal. But weakening demand in France may have prompted the diversion, with the country's piped exports to Italy and Belgium near capacity over 1-4 December, averaging 198 GWh/d, up from 155 GWh/d over the same period a month earlier. If delivered to Everett, the cargo would be Egypt's first LNG export to the US since 2012, according to Kpler data. Egypt's LNG exports have declined sharply since 2022 on lower domestic gas production, falling from 7.14mn t that year to 460,000t so far this year. Despite importing much more gas than it exports, the country continues to ship out LNG to incentivize upstream investment. Everett, owned by US utility Constellation Energy, last imported a cargo in September, ship-tracking data from Kpler show. Imports last winter were limited to a partial cargo each in December and January. Though the US is the world's largest LNG exporter, the Jones Act requires ships going from one US port to another to sail under the US flag. Only one LNG carrier in the global fleet complies with the century-old cabotage law. By Tray Swanson Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
US LNG margins tighten on higher Henry Hub prices
US LNG margins tighten on higher Henry Hub prices
Houston, 5 December (Argus) — A narrowing spread between US and European LNG prices and high freight rates in the Atlantic basin have pushed the front-month indicative long-term LNG contract cost above the spot Gulf coast fob price for the first time in two years. But the premium over the spot price will likely be brief, and limited flexibility in annual delivery plans will likely leave export schedules unchanged, with the impact solely on profit margins rather than fundamentals. A steeper backwardation in the US' Henry Hub forward curve compared to the northwest European LNG forward curve beyond February, as well as a steep backwardation in charter rates, means US LNG offtakers likely will not need to alter export plans. Liquefaction fees are also considered a sunk cost, and the Henry Hub remains comfortably below European LNG prices to more than cover the shipping cost between the two markets. This means there is still a strong financial incentive to maximise US LNG export volumes. The indicative long-term LNG contract price — 115pc of Henry Hub plus a $3/mn Btu liquefaction fee — has exceeded the Argus Gulf coast (AGC) spot fob price since 28 November, climbing to a premium of 69¢/mn Btu on 4 December. That premium came with the front-month Henry Hub price at a nearly three-year high of $5.06/mn Btu on forecasts for cold weather and US LNG exports at a record high. At the same time, the front-month NW Europe LNG des price was at $8.83/mn Btu, the lowest since May 2024, with warmer-than-normal weather forecast in Europe and EU underground storage well-supplied. A surge in freight rates, primarily driven by higher Atlantic basin loading demand, including at the 27.2mn t/yr Plaquemines plant, widened the spread between the AGC fob price and delivered spot prices in northwest Europe. The spread grew to 96¢/mn btu on 24 November, near the peak of the freight rally, up from 28¢/mn Btu in mid-October (see spread chart) . The wider spread pushed the AGC fob price for January loading below the indicative long-term LNG contract price for the same month. Forward freight rates are in steep backwardation in the first quarter of 2026, which is reflected in a tighter AGC-NW Europe spread over that span, as are Henry Hub futures contracts. This puts AGC prices above the indicative long-term contract prices from March through June (see forwards chart) . Although exports are unaffected because of liquefaction costs being considered sunk, the dynamic highlights the tightening margins for US LNG as a supply wave brings more liquefaction capacity on line through the end of the decade. The AGC fob's premium over the long-term indicative contract averaged $4.11/mn Btu through 4 December this year, down from $4.63/mn Btu, $5.37/mn Btu and $20.13/mn Btu in 2024, 2023 and 2022, respectively (see margins chart) . By Tray Swanson AGC-NWE spread and freight rates Tighter margins for US LNG $/mn Btu Indicative long-term contract forwards vs LNG spot prices $/mn Btu Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Spotlight content
Browse the latest thought leadership produced by our global team of experts.
Explore our LNG products
Real time access to our independent and trusted benchmarks, critical market data and analytics, in-depth analysis, and the latest market news. Argus LNG is relied upon by energy companies, governments, banks, regulators, exchanges and many other organizations as source of reliable and unique insights into the global markets.
Key price assessments
Argus prices are recognised by the market as trusted and reliable indicators of the real market value. Explore some of our most widely used and relevant price assessments.