India’s AMNS seek five-year term LNG deal from 2026

: Natural gas
25/02/19

Indian steel manufacturer ArcelorMittal Nippon Steel (AMNS) is seeking a five-year term LNG deal for six cargoes a year starting in 2026 for its direct reduced iron (DRI) plant in the western Gujarat state of Hazira, sources close to the matter have told Argus.

AMNS seeks to sign the deal with prices linked to the US Henry Hub or Brent on a delivered basis to India's west coast either at Petronet's 17.5mn t/yr Dahej terminal or Shell's 5mn t/yr Hazira terminal, the source said. The tender's final stage is expected to close by 27 February.

The deal may equate to 1.8mn t of LNG supply over the period to 2030, assuming a 60,000t LNG cargo size.

The Hazira plant has crude steel production capacity of 8.8mn t/yr, according to ArcelorMittal's September 2024 report. As much as 65pc of the capacity is based on DRI. The firm is on track to expand its low-cost steel-making capacity to 15mn t by 2026, the report says. This supply pact also underscores a trend in the global steel industry to use cleaner energy sources to produce green steel.

The firm imports up to 75pc of its 1.72mn t in natural gas requirements on an annualised basis, a company official told Argus last year.

The steelmaker had last signed a 10-year deal to buy LNG from Shell, with deliveries to start from 2027, at a 11.5 percentage of Brent crude prices that still remains one of the lowest-heard slopes for an Indian term LNG supply contract.

And AMNS has a deal with TotalEnergies for 500,000 t/yr that is scheduled to expire in 2026. The firm may consider extending it next year, another source said.

India's demand for LNG term contracts continues to grow as several gas majors signed LNG contracts during the India Energy Week event.

India's state-run Bharat Petroleum has signed a five-year LNG agreement with UAE's state-owned Adnoc at 115pc of Henry Hub price plus a constant of $5.66, similar to the Gail five-year term LNG deal signed in December, sources told Argus.

State-owned refiner IOC signed a 14-year sales and purchase agreement for up to 1.2mn t/yr of LNG, valued at $7bn-9bn with Adnoc Gas, during the event. The deliveries are set to begin in 2026, and the cargoes will be sourced from the UAE's 6mn t/yr Das Island liquefaction facility. The deal was signed at 12.5pc of Brent crude prices, sources told Argus.

And state-owned Gujarat State Petroleum (GSPC) during the event signed a 400,000 t/yr of LNG deal with TotalEnergies for 10 years to begin from 2026.

Under this deal, TotalEnergies will deliver up to six cargoes a year to GSPC. The deal was signed at 119pc of Henry Hub price plus a constant of $4.4, sources told Argus.

By Rituparna Ghosh

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25/03/12

US gas producers gear up for return to growth

Firms have changed their tune since the start of the winter, as weather-related factors have increased the appeal of boosting output, writes Julian Hast New York, 12 March (Argus) — Some large US natural gas-focused producers plan to boost their output in the coming years, in response to higher prices and booming US LNG export capacity. This would reverse a years-long trend among US producers of holding output steady to avoid oversupply, which drags down prices. The largest producer of US gas by volume, Expand Energy, aims to lift production by 3.4pc from last year to 7.1bn ft³/d (201mn m³/d) in 2025 and to boost drilling to bring on line 300mn ft³/d of sidelined production capacity that could hit the market in 2026. Fellow US gas producer Comstock Resources plans to add drilling rigs in the Haynesville shale of east Texas and northern Louisiana this year in a bid to offset output declines triggered by low prices in 2024 and bring new output on line when needed. US firm Range Resources, which operates in the Appalachian region, expects to boost production by 19pc from 2024 to 2.6bn ft³/d by 2027, with most of this growth set to take place in 2026-27, when the majority of the planned new LNG export terminals on the US Gulf coast are slated to begin operations. Range's sharp upward growth trajectory represents a break from its recent past, given that its 2024 output was just 2.5pc higher than in 2020. US gas producers appear poised to raise output by about 2bn ft³/d combined over the next 12-24 months, to refill inventories that have been depleted by a cold 2024-25 winter season and to keep up with booming LNG exports, according to investment bank RBC Capital Markets. But if every US gas producer grows at same the rate that Range Resources envisages, "the macro backdrop could quickly deteriorate", US bank Tudor Pickering Holt said in a note to clients last month. US gas inventories were at an 80bn ft³ deficit to the five-year average at the end of February, compared with a 215bn ft³ surplus on 1 November, according to US government agency the EIA. US gas prices now have now climbed above the marginal breakeven price of the industry, Expand Energy chief executive Nick Dell'Osso says, putting the US breakeven US gas price at about $3.50/mn Btu. This means "supply will ultimately show up and compete", he says. Expand Energy and fellow US producer EQT, which made the same estimation of the industry breakeven price early last year, say their own breakeven figures are lower because of their ample acreage in the Marcellus and Utica shale formations of Pennsylvania, Ohio and West Virginia, where production costs are lower. Nymex gas futures prices at the US benchmark Henry Hub in Louisiana for delivery in 2026 settled at $4.38/mn Btu on 7 March, up from $3.91/mn Btu at the start of this year. Fair-weather friend The recent growth plans of US producers stand in contrast with many producers' reluctance to boost output earlier this winter, in response to weather-driven shifts in supply and demand. "You don't want to grow for a season" but rather "grow for something that is durable over several years", Dell'Osso said in January. And the production plans of gas-focused firms may end up being overshadowed by those of crude-focused players in the Permian basin of west Texas and southeast New Mexico. These are set to remain the main drivers of production growth in the coming months, thanks to new gas pipeline infrastructure connecting associated gas supply to end markets near the US Gulf coast. Total US marketed gas production is forecast to increase to 114.7bn ft³/d this year and 117.9bn ft³/d in 2026, from 113.1bn ft³/d in 2024, the EIA says. Permian basin output is expected to account for 75pc, or 3.6bn ft³/d, of the additional production by 2026, with output from the basin increasing by 7pc/yr in 2025-26. This would be slower than the 14pc/yr recorded in 2022-24 but would still make it the US' fastest-growing production area. Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Brazil's Marquise Ambiental invests in 6 RNG plants

25/03/12

Brazil's Marquise Ambiental invests in 6 RNG plants

Sao Paulo, 12 March (Argus) — Brazilian landfill company Marquise Ambiental will invest R400mn ($68mn) in six biogas plants with an estimated total output of around 40.8mn m³/yr. The six plants will be in southeastern Sao Paulo state, northeastern Ceara and Rio Grande do Norte states, and northern Rondonia and Amazonas states, the company said. The Amazonas state plant, in the capital Manaus, is set to produce up to 18mn m³/yr of biogas and should prevent 300,000 metric tonnes (t) of CO2 equivalent (CO2e) from being released into the atmosphere. The Sao Paulo plant is forecast to produce 4.6mn m³/yr, while the Ceara plant is set to produce 2.8mn m³/yr. Meanwhile, the Rio Grande do Norte state plants, Braseco and Potiguar, are forecast to have output of 9mn m³/yr and 4mn m³/yr, respectively. The Rondonia plant is set to have an output of 2.1mn m³/yr, according to the company. The investment will happen in the next three years, but the company did not disclose when operations at each plant will begin. Marquise Ambiental has one 36.5mn m³/yr plant operating in Ceara , dubbed GNR Fortaleza. It is a joint venture between the firm and gas company Ecometano. By Maria Frazatto Planned Marquise biogas plants m³/yr Name State Capacity Osasco Sao Paulo 4,687,000 Braseco Rio Grande do Norte 9,007,000 Potiguar Rio Grande do Norte 4,097,000 Aquiraz Ceara 2,853,000 Manaus Amazonas 18,092,000 Porto Velho Rondonia 2,160,000 Total 40,896,000 Marquise Ambiental Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Low gas storage bookings may drive German stockdraw

25/03/12

Low gas storage bookings may drive German stockdraw

London, 12 March (Argus) — Low gas storage bookings for gas year 2025-26 may already be driving withdrawals and may continue to do so in the coming months. German stocks were at about 79.8TWh on Tuesday morning, filling 31.8pc of capacity. That was well below the 131TWh three-year average for this date and the 171TWh in storage a year earlier. Stronger withdrawals this winter were at least partly driven by higher heating demand as well as slower European imports of LNG and Russian pipeline gas compared with a year earlier. But market dynamics for upcoming storage years may also be encouraging withdrawals. A backwardated forward curve, with prompt prices holding substantially higher than contracts in winter 2025-26 and further along the curve, has incentivised the stockdraw over maintaining stocks. That said, prices for the summer quarters have risen above the prompt recently, so some firms could have a slight incentive to keep gas in storage past the end of this storage year. But the inverted THE summer-winter spread has disincentivised capacity bookings for the upcoming storage year. Summer prices holding above winter prices removes the commercial incentive to inject or book storage space profitably. And storage operators have struggled to sell space in recent months, with many auctions closing unsuccessfully as bidders cannot profitably hedge injections for the contract period. In the prevailing environment, only about 55pc of all German storage space has been booked for the 2025-26 storage year, leaving at least 103.5TWh of capacity unallocated, data show ( see data and download ). By contrast, firms had booked 99.7pc of German capacity for the 2024-25 storage year. Storage sites with low or no bookings might be driving withdrawals, as firms near the end of some storage contracts. At sites where some capacity is booked for the next storage year, firms could sell their stocks to other capacity holders if there is no financial incentive for withdrawing it. But at the six sites with no 2025-26 bookings yet — Rehden, Wolfersberg, Harsefeld, Frankenthal, the VNG-operated Jemgum caverns and SEFE's Speicherzone Nord — firms cannot sell gas in-store as there are no available buyers to transfer gas-in-store to, incentivising firms to empty stocks ahead of the summer 2025 filling season. Consequently, sites with no booked capacity for the upcoming storage year currently are filled less than most other German sites ( see graph ). The remaining sites suggests a correlation between 2025-26 bookings and stocks, as sites with a lower proportion of capacity booked for the next storage year tend to be less full, following stronger withdrawals this winter ( see withdrawals trajectory graph ). Stock dilemma Before the 2024-25 storage year ends on 31 March, any capacity holder left with stocks must decide either to withdraw that gas or sell it to a company holding 2025-26 capacity, if there is sufficient storage space booked at the individual site. Barring additional capacity sales, that suggests that about 7TWh may need to be withdrawn on contractual grounds alone, not accounting for weather or withdrawals from fully-booked sites. About 5.6TWh of that is stored at Rehden, Germany's largest storage site, whose operator SEFE Storage allows capacity holders to withdraw 10pc of their stocks up to two months after the storage year ends . Rehden was filled to 12.1pc of capacity on Tuesday morning, leaving about 1TWh to be withdrawn even if all capacity holders utilise that 10pc allowance. Four of the six sites with no 2025-26 bookings are depleted fields or aquifers, which have lower withdrawal and injection rates than salt caverns and offer capacity holders less flexibility to react to unusual price spreads. Caverns often offer faster injection and withdrawal speeds, so could still be used economically in summer by, for example, reacting to price volatility rather than seasonal spreads. Faster cycling also allows cavern capacity holders to wait longer before starting pre-winter injections, potentially allowing them to wait until the summer-winter spread normalises before injecting. Slower-cycling sites such as aquifers and depleted fields are usually drawn down more consistently in winter as their slower injections and withdrawals reduce their flexibility. That said, some operators might need to inject into caverns to maintain their structural integrity. This might stop withdrawals or possibly support a minimum of injections ahead of or early in the filling season. German storage operator Uniper Energy Storage bought some gas to store as de-facto cushion gas at its Etzel EGL and Etzel ESE sites last week to comply with German law. Restrictions on minimum pressure are enforced by mining authorities and can differ by site, storage operators have told Argus . By Lucas Waelbroeck Boix and Till Stehr Storage bookings next year vs current fill level % Fill level trajectories grouped by site type % Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US gas CEOs declare victory over energy transition

25/03/12

US gas CEOs declare victory over energy transition

Houston, 12 March (Argus) — The energy industry is finally recognizing that more renewable resources will not deter demand growth for natural gas anytime soon, the chief executives of major US natural gas and LNG producers said today. Two years ago, renewables were the principle talking point of the energy industry, said Michael Smith, chief executive of Freeport LNG, at the CERAWeek by S&P Global conference in Houston, Texas. "That has completely changed," Smith said. "There is a recognition within the industry that the energy transition is not going to be using natural gas just as a bridge fuel." That recognition comes from growing overseas demand for US LNG, the desire by countries to convert coal-fired power generation to gas-fired generation, and more recently, booming power demand by planned data centers to run artificial intelligence software, said Toby Rice, chief executive of EQT, the second-largest US gas producer by volume. But despite growing demand, environmental and local opposition to the construction of new US interstate gas pipelines poses a challenge to the industry's ability to produce and transport enough gas to fulfill that demand, Rice said. "The biggest challenge that's facing our industry is this pipeline cancellation movement," Rice said. Construction of interstate gas pipelines in the US has become difficult in recent years as environmentalists and landowners pressure state governments to withhold air and water quality permits needed for those projects. Rice's controversial 2 Bcf/d (57mn m³/d) Mountain Valley Pipeline (MVP), which connects gas fields in West Virginia with markets 300 miles away in Virginia, is the only major greenfield interstate gas pipeline project in the eastern US that has overcome legal opposition in recent years. It was allowed to bypass federal permitting hurdles through an agreement in 2023 between former President Joe Biden and Republicans to raise the limit on the federal debt, provoking outrage from environmental groups and some Democrats. The pipeline began service in June 2024, six years behind schedule and with a price tag of $7.85bn, compared to an original estimate of $3.5bn. MVP "is a piece of infrastructure that they said was not needed", even though the pipeline was operating at maximum capacity this winter, Rice said. "Everybody should be incredibly concerned that it takes an act of Congress to get a pipeline built in this country." By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Trump to declare power 'emergency' in some states

25/03/11

Trump to declare power 'emergency' in some states

Washington, 11 March (Argus) — President Donald Trump said today he intends to declare a "National Emergency on Electricity" in states that could be affected by Ontario's imposition of a 25pc surcharge on electricity exports and further threat to cut off exports entirely. The emergency declaration will allow the US to alleviate the "abusive threat" from losing electricity imports from Canada, Trump wrote in a post on social media. Trump said in response to the surcharge, he would double existing tariffs on Canadian steel and aluminum , and warned Canada that it would pay a high cost if Ontario cuts off the flow of electricity to the US. "Can you imagine Canada stooping so low as to use ELECTRICITY, that so affects the life of innocent people, as a bargaining chip and threat?" Trump wrote. "They will pay a financial price for this so big that it will be read about in History Books for many years to come!" On Monday, Ontario put a 25pc fee on its electricity exports to New York, Michigan and Minnesota in response to Trump's tariffs on Canada. Ontario premier Doug Ford said he was applying "maximum pressure" on the US over its tariff war, and threatened to cut off exports entirely if Trump increased tariffs further. Ontario was the largest exporter of electricity to the US in 2023, sending 15.2 TWh to the US. Trump already declared a national energy emergency on 20 January, unlocking emergency authorities to fast-track permitting and seek to retain production of baseload power plants. Trump has yet to offer more details on the electricity emergency, but the US Department of Energy (DOE) can issue emergency orders that would allow power plants to run at maximum capacity or waive some environmental regulations. DOE did not immediately respond to a request for comment. The New York Independent System Operator, which runs the state's electric grid, said it was analyzing the effects of Ontario's orders and expects to have "adequate reserves to meet reliability criteria and forecast demand for New York." By Chris Knight Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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