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.
Plaquemines LNG loadings set new record
Plaquemines LNG loadings set new record
Houston, 1 December (Argus) — Eight LNG carriers loaded at Venture Global's 27.2mn t/yr (3.6bn ft³/d) Plaquemines export facility in Louisiana in the week that began 24 November, a record for the terminal, ship-tracking data from Kpler show. The rise is part of the faster-than-expected ramp-up at Plaquemines, which is the second largest US LNG export facility behind Cheniere's 33mn t/yr Sabine Pass terminal. Plaquemines exported 590,000t in the week that began 24 November, raising the four-week moving average to 510,000t (see chart) . That would equate to 26.52mn t/yr if annualized, above Plaquemines' nameplate capacity of 20mn t/yr. Plaquemines exported its first cargo in late December 2024 and received federal approval to run feedgas through its final two liquefaction trains in October. Its previous weekly loadings high was seven, which occurred five times between late September and late November. Venture Global told investors in November that Plaquemines would export between 90-94 cargoes in the fourth quarter. The plant exported 61 cargoes in October-November, Kpler data show, putting it in the middle of the guidance if it exports one cargo per day in December. And weekly feedgas nominations to Plaquemines averaged more than 4bn ft³/d for the first time in the week that began 24 November. Flows averaged 4.08bn ft³/d, up from 3.98bn ft³/d the previous week, pipeline data show (see chart) . Feedgas nominations to all US LNG export facilities averaged 18.17bn ft³/d last week, though that excludes flows on the 1.7bn ft³/d ADCC pipeline, an instrastate line that connects to Cheniere's 17.4mn t/yr Corpus Christi LNG plant. Instrastate pipelines are not required to publicly post pipeline flows, but export data from Kpler and other pipeline flows to Corpus Christi LNG indicate nominations on ADCC were likely around 700mn ft³/d in November. The strong pace at Plaquemines is part of higher loading demand in the Atlantic basin than market participants expected, leading to a sharp rise in spot charter rates for LNG carriers in the Atlantic. The Argus Round Voyage rate for two-stroke carriers traveling from the US Gulf Coast to Europe within a 20-45 day period (ARV5) closed at $145,000/d on 1 December, up from $22,000/d on 15 October. By Tray Swanson Feedgas to Plaquemines bn ft³/d Weekly Plaquemines loadings ’000t Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Australia’s CS delays gas-fired generator to 2028
Australia’s CS delays gas-fired generator to 2028
Sydney, 1 December (Argus) — Australian state-owned utility CS Energy's gas-fired 400MW Brigalow Peaking Power Plant in Queensland will come on line in late 2028, a year later than originally announced. The delay comes as CS has formed a joint venture with Australian gas infrastructure firm APA to fund Brigalow, APA said on 1 December. APA will take a 80pc non-operated stake in the project for which it will building a connection to the gas grid, while CS will control the remaining 20pc and operate the facility. Construction of the plant will take three years and will include the installation of 12 gas turbines, with the power plant now set to be commissioned at the end of 2028, a CS spokesperson said. The project will cost about A$1bn ($650mn), an analyst with RBC Capital Markets said. The companies expect to complete an engineering design before June 2026, which will determine project costs. CS recently announced a gas supply agreement with Australian gas company Senex Energy for up to 58.4PJ (1.56bn m³) over 10 years. Queensland's conservative Liberal National Party government included [A$479mn] (https://direct.argusmedia.com/newsandanalysis/article/2744404) in its 2025-26 state budget for the Brigalow peaking plant. This investment is in line with the state's five-year energy roadmap released in October, which outlines plans to keep coal-fired power plants operational until the late-2030s and mid-2040s and to introduce new gas-fired capacity. Queensland's electricity generation in the last 12 months consisted of 72pc black coal, 11pc solar and a 7pc share each for gas and wind, data from the Australian Energy Market Operator show. The state has the highest percentage of black coal generation in the national energy market, followed by New South Wales' 68pc. By Susannah Cornford Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Syria’s energy reset reflects geopolitical shifts
Syria’s energy reset reflects geopolitical shifts
The early signs of an energy investment revival are clear, but risk still lies in some of the same forces that tore the country apart, writes Bachar Halabi Dubai, 28 November (Argus) — Syria's energy sector is re-emerging as a focal point for regional and international investment after more than a decade of war and isolation, with major gas, power and upstream initiatives accelerating since US and European sanctions were partially suspended earlier this year. The first sustained efforts are under way since the fall of Bashar al-Assad's regime late last year to rebuild the country's electricity system and revive domestic oil and gas production, drawing in Gulf states, Turkish operators, US energy service firms and multilateral institutions. This also underscores Syria's geostrategic realignment in the Arab world and the Levant. But the scale of the challenge is vast and the devil lies in the politics. The country's electricity generation capacity has collapsed from around 9.5GW before the 2011 conflict to just 1.6GW today, according to UN data. Over 70pc of power plants and transmission lines are severely damaged, and years of underinvestment have left the grid able to deliver only 2–4 hours of electricity a day in many areas. Oil and gas output has plummeted. Crude production is currently at 90,000–120,000 b/d, down from over 400,000 b/d pre-2011, while natural gas supply fell to around 3bn m³/yr in 2023 from 8.7bn m³/yr in 2011. Syrian authorities estimate the country needs over $30bn to rehabilitate its oil, gas, mineral, electricity and water sectors, including roughly $10bn urgently required for power generation, transmission and distribution. A newly consolidated energy ministry has been charged with rebuilding the energy system, re-establishing regulatory oversight and co-ordinating foreign investment. But the level of corruption that took hold in wartime remains a potential challenge in this new era. The most visible energy development is the emergence of large-scale, foreign-funded power projects, unlike anything Syria witnessed during the Assad era. The energy ministry signed $7bn of investment and power-purchase agreements (PPAs) in November with a consortium led by Qatar's UCC Holding that brought together Turkey's Kalyon GIS Energy and Cengiz Energy, and US-based Power International. The package includes 5GW of new capacity, four combined-cycle gas turbine (CCGT) plants — North Aleppo (1.2GW), Deir Ezzor (1GW), Zayzoun (1GW) and Mhardeh (800MW) — and 1GW of solar photovoltaic capacity across Aleppo, Homs and Deir Ezzor. Structured as a public-private partnership, the deal is the first major international investment in Syria's power sector since 2011 and sets a template for future independent power projects. US involvement The consortium is finalising build-own-operate and build-operate-transfer structures, long-term PPAs and government guarantees to enable phased financing. Construction timelines range from under two years for the solar parks to around three years for the CCGTs, once financing closes. The US is shaping the reconstruction effort. US sanctions on Syria's energy sector were lifted at the end of June, and Baker Hughes, Hunt Energy and Argent LNG have been mandated to develop a comprehensive "energy and power generation masterplan" for gas, oil and electricity infrastructure in government-held areas west of the Euphrates. Upstream activity is likewise restarting. In November, following the visit of Syrian president Ahmad al-Sharaa to the White House, state-run Syrian Petroleum signed an initial agreement with US oil firm ConocoPhillips and US-based Novaterra Energy to develop existing gas fields and undertake new exploration. The companies aim to add 4mn–5mn m³/d of new gas production within a year, contributing to Damascus' target of reaching 22mn m³/d — the volume required to fully fuel Syria's thermal power fleet. Other firms, including UK-based Gulfsands Petroleum and Russia's Tatneft, have held talks to reinstate suspended operations. But without reliable supply, even the least ambitious CCGT buildout will stall, so Syria is taking a three-pronged approach. The first centres on imports through the Turkey–Azerbaijan route. Azerbaijan's state-owned Socar said on 2 August that it would export 1.2bn m³/yr to Syria using a repaired pipeline linking Kilis in southern Turkey to Aleppo. Initial flows of 3.4mn m³/d are intended for the refurbished Aleppo power plant, with capacity expandable to 6mn m³/d as downstream infrastructure is completed. The second prong involves imports from Qatar via the Arab Gas Pipeline. Qatar pledged deliveries in March via the Jordan–Syria segment of the line, which officials say is operational and undergoing upgrades inside Syria. Authorities say the line has been connected to Turkey, for potential north–south interoperability. The third prong is domestic output recovery. The ConocoPhillips–Novaterra agreement and smaller rehabilitation efforts in central and southern fields aim to stabilise supply. Abu Dhabi-listed Dana Gas has signed an agreement to redevelop and expand several gas fields in central Syria. Together, these supplies will support the new CCGT capacity and stabilise legacy power plants. Sanctions relief is also reshaping Syria's crude supply patterns, indicating the broader geopolitical repositioning under way. The state-owned Banias refinery, with around 140,000 b/d of capacity, relied almost exclusively on Iranian and then Russian supplies after 2012. But those flows are shifting as Damascus aims to diversify its imports to end its single-source dependency, which often comes with a political price. Syria has imported 48,000 b/d of crude this year, with 89pc of this Russian Arctic grades and the remainder its first post-sanction Saudi crude deliveries. The latter reflect Syria's agreement in September with the Saudi Fund for Development for a 1.65mn bl crude grant, delivered in two cargoes this month. It is unclear whether Saudi Arabia intends to keep those flows running. But the return of Mideast Gulf energy imports signals deeper regional engagement. Saudi Arabia, Qatar, Turkey and the UAE are all seeking economic footholds in Syria's reconstruction, while western governments frame the country's recovery as an opportunity to reduce Iranian and Russian influence in the Levant. Rules of re-engagement Equally importantly, multilateral institutions are re-entering the country after decades of disengagement. The World Bank in June approved a $146mn grant to rehabilitate two 400kV transmission lines linking Syria with Jordan and Turkey — its first money for the country in nearly four decades. Yet the return of foreign capital does not guarantee smooth reconstruction. The emerging investment must contend with the structural realities of a fragmented state, creating a new layer of political and operational risk. Security hazards also persist, not least internal violence and continued Israeli airstrikes. Then there is the division between government-held areas and eastern regions under Syrian-Kurdish influence, where most oil and gas reserves lie, complicating efforts to recreate a unified regulatory and financial framework. Questions also arise over the durability of contracts signed with a transitional government that is not formally representative and that is still attempting to assert control. The early contours of Syria's energy revival are unmistakable. But the reconstruction and rehabilitation effort remains hostage to the same forces that fractured Syria in the first place — unaccountable authority, volatile security and an unsettled political transition. The next few years will determine whether Syria's energy reset is a foundation for long-term stability or a fragile alignment vulnerable to the region's shifting power dynamics. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.
Narrow spreads could bring gas storage closures
Narrow spreads could bring gas storage closures
London, 26 November (Argus) — Narrow and at times inverted seasonal spreads have weighed on the uptake of capacity and profitability of Europe's slower-cycling storage facilities, which has led to applications to close sites, and may lead to more in the coming years. TTF summer-winter spreads for gas year 2026-27 and 2027-28 have improved in recent months but remained narrow at -€0.97/MWh and at -€1.25/MWh, respectively, at the last close ( see summer-winter spread graph ). And the 2028-29 summer-winter spread closed at -€1.185/MWh. Narrower and even inverted summer-winters spreads limited storage capacity bookings in Europe last year. The 16.5TWh Rough storage site in the UK closed in 2017 because of high operational costs, before reopening during the energy crisis of 2022. At the time of operator Centrica's closure application , the front-summer contract was at a 6.78p/th — €2.56/MWh — discount to the following winter contract across the month of June. The spread between these two contracts had held at an average -4.615p/th or -€1.72/MWh throughout 2016. Since the reopening of the site, Centrica has repeatedly called for regulatory support to "upgrade and redevelop" the facility, while the profits from its storage-focused subsidiary plummeted last year. It has also stressed the need for a "regulatory support model" from the government to prevent Rough's closure given its low profitability. While fast-cycling sites retain a comparative advantage in their capacity to provide quick injections into the grid in moments of peak demand, and allow firms to take advantage of short-term price differentials the inflexibility of slow-cycling sites limit the attractiveness of purchasing and making use of capacity. The slow-cycling 45TWh Rehden storage site is struggling to sell storage capacity for the second year in a row. The site has a maximum 353 GWh/d firm injection capacity and 543 GWh/d firm withdrawal capacity, giving it a churn rate — injection and withdrawal capacity relative to its storage size — of 1.75. This is the fourth-lowest churn rate of any storage site in Germany, and below the 4.9 average rate in the country. Comparatively, the Rough storage site has a 103 GWh/d and 126 GWh/d firm injection and withdrawal capacity, with a 1.25 churn rate. This is below the 8.46 average rate in the UK. Rehden's operator Sefe Storage was only able to sell 30pc of capacity ahead of this winter, after it had to adjust the "product structure" by increasing injection capacity on offer but reducing storage capacity to 24.6TWh. Sefe Storage also indicated in August that it would need government intervention to be able to fill the site to legally-required levels. The company pointed to "unfavourable market conditions" and an "exceptional market situation" as their reason behind its failure to sell storage capacity. The "facility has not been in as high demand on the market as other storage facilities in Germany" [BMWE told Argus ](https://direct.argusmedia.com/newsandanalysis/article/2758349). "Rehden no longer has the same significance for security of supply as it did previously" because of changes in gas supply since 2022, including the expansion and heavy use of LNG, the ministry added. "There are currently no plans to close UGS Rehden," Sefe said when asked for comment on the matter. And the operator of slow-cycling Breitbrunn applied in October for approval to decommission the site on 31 March 2027 after it had struggled to sell capacity this summer. The site has a technical capacity of 11.5TWh, of which only 6.8TWh was booked for the 2025-26 storage year. Breitbrunn has 69 GWh/d of firm injection capacity and 144 GWh/d of firm withdrawal capacity, with 1.48 churn rate, making it the slowest cycling site in Germany. Bayernugs also announced its intention to close its 4.1TWh Wolfersberg storage site — with a 2.36 churn rate. The site has been unable to sell any capacity over the past storage year and has not sold any capacity for the coming storage year so far. The Uelsen, Inzenham-West, Frankenthal and Schmidhausen storage sites in Germany all have a churn rate below 2, making them the slowest-cycling and potentially most-at-risk sites in the country. That said, any storage closure must receive receive government approval beforehand. A possible decommissioning of the Breitbrunn storage site "would not jeopardise the security of supply in Bavaria, Germany or our neighbouring countries", the German economy and energy ministry BMWE told Argus . A good supply balance in Germany and the connection of Austrian storage facilities Haidach and 7Fields to the German grid further support this conclusion, the ministry added. In the Netherlands, the government has yet to take a decision regarding operator Nam's phase-out plan for the 59.3TWh Norg low-calorie site. Nam envisions a halt to summer injections and the drawdown of stocks during the winter as part of the plan. The closure of the Norg storage site has been projected as part of plans to phase out large underground gas infrastructure in the Groningen region . The site has a maximum 449 GWh/d firm injection capacity and 733 GWh/d firm withdrawal capacity, with a 1.71 churn rate. Storage closures in Europe might nevertheless allow governments to produce or use the remaining cushion gas as emergency stocks . By Lucas Waelbroeck Boix TTF summer-winter spreads €/MWh 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.